Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
(Mark One)
[ X ]  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2016
or
[    ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from        to        
Commission File No. 1-8968
ANADARKO PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
Delaware
 
76-0146568
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
1201 Lake Robbins Drive, The Woodlands, Texas
 
77380-1046
(Address of principal executive offices)
 
(Zip Code)
Registrant’s telephone number, including area code (832) 636-1000
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    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 April 19, 2016, is shown below:
Title of Class
 
Number of Shares Outstanding
Common Stock, par value $0.10 per share
 
510,426,628


TABLE OF CONTENTS
 
Page
Item 1.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 2.
 
 
 
 
 
 
Item 3.
Item 4.
 
 
Item 1.
Item 1A.
Item 2.
Item 6.

Table of Contents

PART I. FINANCIAL INFORMATION
Item 1.  Financial Statements
ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
 
 
Three Months Ended 
 March 31,
millions except per-share amounts
 
2016
 
2015
Revenues and Other
 
 
 
 
Oil and condensate sales
 
$
850

 
$
1,419

Natural-gas sales
 
366

 
641

Natural-gas liquids sales
 
178

 
232

Gathering, processing, and marketing sales
 
240

 
293

Gains (losses) on divestitures and other, net
 
40

 
(264
)
Total
 
1,674

 
2,321

Costs and Expenses
 
 
 
 
Oil and gas operating
 
208

 
296

Oil and gas transportation
 
242

 
305

Exploration
 
126

 
1,083

Gathering, processing, and marketing
 
215

 
254

General and administrative
 
449

 
307

Depreciation, depletion, and amortization
 
1,149

 
1,256

Other taxes
 
117

 
182

Impairments
 
16

 
2,783

Other operating expense
 
16

 
63

Total
 
2,538

 
6,529

Operating Income (Loss)
 
(864
)
 
(4,208
)
Other (Income) Expense
 
 
 
 
Interest expense
 
220

 
216

(Gains) losses on derivatives, net
 
297

 
152

Other (income) expense, net
 
—

 
47

Tronox-related contingent loss
 
—

 
5

Total
 
517

 
420

Income (Loss) Before Income Taxes
 
(1,381
)
 
(4,628
)
Income tax expense (benefit)
 
(383
)
 
(1,392
)
Net Income (Loss)
 
(998
)
 
(3,236
)
Net income (loss) attributable to noncontrolling interests
 
36

 
32

Net Income (Loss) Attributable to Common Stockholders
 
$
(1,034
)
 
$
(3,268
)
 
 
 
 
 
Per Common Share
 
 
 
 
Net income (loss) attributable to common stockholders—basic
 
$
(2.03
)
 
$
(6.45
)
Net income (loss) attributable to common stockholders—diluted
 
$
(2.03
)
 
$
(6.45
)
Average Number of Common Shares Outstanding—Basic
 
509

 
507

Average Number of Common Shares Outstanding—Diluted
 
509

 
507

Dividends (per common share)
 
$
0.05

 
$
0.27


See accompanying Notes to Consolidated Financial Statements.

2
Table of Contents

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
 
 
Three Months Ended 
 March 31,
millions
 
2016
 
2015
Net Income (Loss)
 
$
(998
)
 
$
(3,236
)
Other Comprehensive Income (Loss)
 
 
 
 
Adjustments for derivative instruments
 
 
 
 
Reclassification of previously deferred derivative losses to (gains) losses on
derivatives, net
 
3

 
2

Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
 
(1
)
 
(1
)
Total adjustments for derivative instruments, net of taxes
 
2

 
1

Adjustments for pension and other postretirement plans
 
 
 
 
Net gain (loss) incurred during period
 
(166
)
 
—

Income taxes on net gain (loss) incurred during period
 
61

 
—

Prior service credit (cost) incurred during period
 
(1
)
 
—

Income taxes on prior service credit (cost) incurred during period
 
1

 
—

Amortization of net actuarial (gain) loss to general and administrative expense
 
8

 
13

Income taxes on amortization of net actuarial (gain) loss to general and
administrative expense
 
(3
)
 
(4
)
Amortization of net prior service (credit) cost to general and administrative expense
 
(15
)
 
—

Income taxes on amortization of net prior service (credit) cost to general and administrative expense
 
5

 
—

Total adjustments for pension and other postretirement plans, net of taxes
 
(110
)
 
9

Total
 
(108
)
 
10

Comprehensive Income (Loss)
 
(1,106
)
 
(3,226
)
Comprehensive income (loss) attributable to noncontrolling interests
 
36

 
32

Comprehensive Income (Loss) Attributable to Common Stockholders
 
$
(1,142
)
 
$
(3,258
)


See accompanying Notes to Consolidated Financial Statements.

3
Table of Contents

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)
millions
 
March 31,
2016
 
December 31,
2015
ASSETS
 
 
 
 
Current Assets
 
 
 
 
Cash and cash equivalents ($111 and $100 related to VIEs)
 
$
2,947

 
$
939

Accounts receivable (net of allowance of $12 and $11)
 
 
 
 
Customers ($47 and $81 related to VIEs)
 
633

 
652

Others ($81 and $84 related to VIEs)
 
1,759

 
1,817

Other current assets
 
428

 
573

Total
 
5,767

 
3,981

Properties and Equipment
 
 
 
 
Cost
 
71,541

 
70,683

Less accumulated depreciation, depletion, and amortization
 
38,015

 
36,932

Net properties and equipment ($4,940 and $4,859 related to VIEs)
 
33,526

 
33,751

Other Assets ($624 and $644 related to VIEs)
 
2,304

 
2,268

Goodwill and Other Intangible Assets ($1,244 and $1,220 related to VIEs)
 
6,325

 
6,331

Total Assets
 
$
47,922

 
$
46,331

 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
Current Liabilities
 
 
 
 
Accounts payable ($183 and $179 related to VIEs)
 
$
2,505

 
$
2,850

Current asset retirement obligations
 
297

 
309

Interest payable
 
158

 
247

Other taxes payable ($28 and $18 related to VIEs)
 
339

 
318

Accrued expenses
 
333

 
424

Short-term debt
 
3,025

 
32

Total
 
6,657

 
4,180

Long-term Debt
 
15,726

 
15,636

Other Long-term Liabilities
 
 
 
 
Deferred income taxes
 
4,940

 
5,400

Asset retirement obligations ($131 and $127 related to VIEs)
 
1,760

 
1,750

Other
 
4,138

 
3,908

Total
 
10,838

 
11,058

 
 
 
 
 
Equity
 
 
 
 
Stockholders’ equity
 
 
 
 
Common stock, par value $0.10 per share (1.0 billion shares authorized, 531.1 million and 528.3 million shares issued)
 
53

 
52

Paid-in capital
 
9,328

 
9,265

Retained earnings
 
3,821

 
4,880

Treasury stock (20.7 million and 20.0 million shares)
 
(1,025
)
 
(995
)
Accumulated other comprehensive income (loss)
 
(491
)
 
(383
)
Total Stockholders’ Equity
 
11,686

 
12,819

Noncontrolling interests
 
3,015

 
2,638

Total Equity
 
14,701

 
15,457

Total Liabilities and Equity
 
$
47,922

 
$
46,331

__________________________________________________________________
Parenthetical references on this statement provide March 31, 2016 amounts followed by December 31, 2015 amounts.

See accompanying Notes to Consolidated Financial Statements.

4
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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF EQUITY
(Unaudited)
 
 
Total Stockholders’ Equity
 
 
 
 
 
 
Common
Stock
 
Paid-in
Capital
 
Retained
Earnings
 
Treasury
Stock
 
Accumulated Other
Comprehensive
Income (Loss)
 
Non-
controlling
Interests
 
Total
Equity
millions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at December 31, 2015
 
$
52

 
$
9,265

 
$
4,880

 
$
(995
)
 
$
(383
)
 
$
2,638

 
$
15,457

Net income (loss)
 
—

 
—

 
(1,034
)
 
—

 
—

 
36

 
(998
)
Common stock issued
 
1

 
62

 
—

 
—

 
—

 
—

 
63

Dividends—common stock
 
—

 
—

 
(25
)
 
—

 
—

 
—

 
(25
)
Repurchase of common stock
 
—

 
—

 
—

 
(30
)
 
—

 
—

 
(30
)
Subsidiary equity transactions
 
—

 
1

 
—

 
—

 
—

 
419

 
420

Distributions to noncontrolling interest owners
 
—

 
—

 
—

 
—

 
—

 
(78
)
 
(78
)
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
 
—

 
—

 
—

 
—

 
2

 
—

 
2

Adjustments for pension and other postretirement plans
 
—

 
—

 
—

 
—

 
(110
)
 
—

 
(110
)
Balance at March 31, 2016
 
$
53

 
$
9,328

 
$
3,821

 
$
(1,025
)
 
$
(491
)
 
$
3,015

 
$
14,701



See accompanying Notes to Consolidated Financial Statements.

5
Table of Contents

ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
 
Three Months Ended 
 March 31,
millions
 
2016
 
2015
Cash Flows from Operating Activities
 
 
 
 
Net income (loss)
 
$
(998
)
 
$
(3,236
)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
 
 
 
 
Depreciation, depletion, and amortization
 
1,149

 
1,256

Deferred income taxes
 
(413
)
 
(1,198
)
Dry hole expense and impairments of unproved properties
 
35

 
1,009

Impairments
 
16

 
2,783

(Gains) losses on divestitures, net
 
(2
)
 
334

Total (gains) losses on derivatives, net
 
299

 
152

Operating portion of net cash received (paid) in settlement of derivative instruments
 
105

 
91

Other
 
115

 
45

Changes in assets and liabilities
 
 
 
 
Tronox-related contingent liability
 
—

 
(5,210
)
(Increase) decrease in accounts receivable
 
46

 
357

Increase (decrease) in accounts payable and accrued expenses
 
(403
)
 
(279
)
Other items, net
 
(86
)
 
(608
)
Net cash provided by (used in) operating activities
 
(137
)
 
(4,504
)
Cash Flows from Investing Activities
 
 
 
 
Additions to properties and equipment and dry hole costs
 
(1,022
)
 
(1,957
)
Divestitures of properties and equipment and other assets
 
35

 
22

Other, net
 
14

 
10

Net cash provided by (used in) investing activities
 
(973
)
 
(1,925
)
Cash Flows from Financing Activities
 
 
 
 
Borrowings, net of issuance costs
 
4,682

 
4,583

Repayments of debt
 
(1,608
)
 
(2,830
)
Financing portion of net cash received (paid) for derivative instruments
 
(555
)
 
(146
)
Increase (decrease) in outstanding checks
 
(150
)
 
(39
)
Dividends paid
 
(25
)
 
(139
)
Repurchase of common stock
 
(30
)
 
(36
)
Issuance of common stock, including tax benefit on share-based compensation awards
 
30

 
12

Sale of subsidiary units
 
440

 
31

Distributions to noncontrolling interest owners
 
(78
)
 
(67
)
Proceeds from conveyance of future hard minerals royalty revenues, net of transaction costs
 
413

 
—

Net cash provided by (used in) financing activities
 
3,119

 
1,369

Effect of Exchange Rate Changes on Cash
 
(1
)
 
(1
)
Net Increase (Decrease) in Cash and Cash Equivalents
 
2,008

 
(5,061
)
Cash and Cash Equivalents at Beginning of Period
 
939

 
7,369

Cash and Cash Equivalents at End of Period
 
$
2,947

 
$
2,308



See accompanying Notes to Consolidated Financial Statements.

6
Table of Contents

ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


1. Summary of Significant Accounting Policies

General  Anadarko Petroleum Corporation is engaged in the exploration, development, production, and marketing of oil, condensate, natural gas, and natural gas liquids (NGLs), and in the marketing of anticipated production of liquefied natural gas (LNG). In addition, the Company engages in the gathering, processing, treating, and transporting of oil, condensate, natural gas, 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 Consolidated Financial Statements have been prepared in conformity with generally accepted accounting principles in the United States (GAAP). The Consolidated Financial Statements include the accounts of Anadarko and subsidiaries in which Anadarko holds, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs) for which Anadarko is the primary beneficiary. All intercompany transactions have been eliminated. Undivided interests in oil and natural-gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities over which Anadarko has the ability to exercise significant influence over operating and financial policies and VIEs for which Anadarko is not the primary beneficiary are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost, and subsequently adjusted for the Company’s proportionate share of earnings, losses, and distributions. Other investments are carried at original cost. Investments accounted for using the equity method and cost method are reported as a component of other assets. Certain prior-period amounts have been reclassified to conform to the current-year presentation.

Use of Estimates  The preparation of financial statements in accordance with GAAP 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 require capitalized debt issuance 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. The Company adopted these ASUs on January 1, 2016, using a retrospective approach. The adoption resulted in a reclassification that reduced other current assets and short-term debt by $1 million and reduced other assets and long-term debt by $82 million on the Company’s Consolidated Balance Sheet at December 31, 2015.
The FASB issued ASU 2015-02, Consolidation (Topic 810)—Amendments to the Consolidation Analysis. The Company adopted this ASU on January 1, 2016. In accordance with the new ASU, Western Gas Equity Partners, LP (WGP) and Western Gas Partners, LP (WES), publicly traded consolidated subsidiaries of the Company, are considered VIEs for which the Company is the primary beneficiary. Prior to adoption of the ASU, WGP and WES were consolidated by the Company under the voting interest model and, after adoption, the Company will continue to consolidate WGP and WES under the variable interest model. While this ASU requires additional financial statement disclosure, it has no impact on the Company’s consolidated results of operations, cash flows, or financial position. See Note 17—Variable Interest Entities.

7
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1. Summary of Significant Accounting Policies (Continued)

The FASB issued ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. This ASU will simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This ASU is effective for annual and interim periods beginning in 2017 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 2016-02, Leases (Topic 842). This ASU requires the lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet and disclose key information about their leasing transactions. This ASU is effective for annual and interim periods beginning in 2019. The Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements.
The FASB issued ASU 2016-01, Financial Instruments—Overall: Recognition and Measurement of Financial Assets and Financial Liabilities (Subtopic 825-10). This ASU amends existing requirements on the classification and measurement of financial instruments. Changes to the current requirements primarily affect the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. This ASU is effective for annual periods beginning in 2018 with early adoption of certain provisions 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 (Topic 606), ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), and ASU 2016-10, Revenues from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, which supersede 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 require an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Company is required to adopt the new standards in the first quarter of 2018 using one of two retrospective application methods. The Company is continuing to evaluate the provisions of these ASUs, and has not determined the impact these standards may have on its consolidated financial statements and related disclosures or decided upon the method of adoption.

2. Inventories

The following summarizes the major classes of inventories included in other current assets:
millions
March 31,
2016
 
December 31,
2015
Oil
$
96

 
$
116

Natural gas
25

 
36

NGLs
67

 
64

Total inventories
$
188

 
$
216


3. Assets Held for Sale

Certain U.S. onshore assets in East Texas/Louisiana included in the oil and gas exploration and production reporting segment satisfied criteria to be considered held for sale during the first quarter of 2016. The sale of these assets closed in April 2016 for a sales price of $107 million, subject to closing adjustments. At March 31, 2016, the balances of assets and liabilities associated with assets held for sale were not material.


8
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

4. Impairments

Impairments of long-lived assets are included in impairment expense in the Company’s Consolidated Statements of Income. The following summarizes impairments of long-lived assets and the related post-impairment fair values by segment:
  
Three Months Ended
millions
Impairment
 
Fair Value (1)
March 31, 2016
 
 
 
Oil and gas exploration and production
 
 
 
Long-lived assets held for use
 
 
 
U.S. onshore properties
$
4

 
$
585

Gulf of Mexico properties
1

 
—

Cost-method investment (2)
1

 
32

Midstream
 
 
 
Long-lived assets held for use
10

 
3

Total
$
16

 
$
620

 
 
 
 
March 31, 2015
 
 
 
Oil and gas exploration and production
 
 
 
Long-lived assets held for use
 
 
 
U.S. onshore properties
$
2,307

 
$
1,299

Midstream
 
 
 
Long-lived assets held for use
476

 
206

Total
$
2,783

 
$
1,505

__________________________________________________________________
(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 first quarter of 2015 were primarily related to the Company’s Greater Natural Buttes oil and gas and midstream properties in the Rockies, which were impaired due to lower forecasted commodity prices.
In addition to the long-lived asset impairments above, the Company recognized a $935 million impairment of unproved Greater Natural Buttes properties during the first quarter of 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.

Potential for Future Impairments  During 2015, the Company recognized significant impairments of proved oil and gas and midstream properties and impairments of unproved oil and gas properties, primarily as a result of lower forecasted commodity prices and related changes to the Company’s drilling plans. While commodity prices continued to decline during the first quarter of 2016, the Company did not recognize any material impairments. At March 31, 2016, the Company’s estimate of undiscounted future cash flows attributable to a certain depletion group with a net book value of approximately $2.1 billion indicated that the carrying amount was expected to be recovered; however, this depletion group may be at risk for impairment if the estimates of future cash flows decline. The Company estimates that, if this depletion group becomes impaired in a future period, the Company could recognize non-cash impairments in that period in excess of $1.0 billion. It is also reasonably possible that prolonged low or further declines in commodity prices, changes to the Company’s drilling plans in response to lower prices, or increases in drilling or operating costs could result in additional impairments.

 


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

5. Suspended Exploratory Well Costs

The Company’s suspended exploratory well costs were $1.1 billion at March 31, 2016, and December 31, 2015. During the three months ended March 31, 2016, suspended exploratory well costs previously capitalized for a period greater than one year since the completion of drilling at December 31, 2015, charged to exploration expense were not material. 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 Cushing, Oklahoma or Sullom Voe, Scotland for oil and Henry Hub, Louisiana for natural gas. Basis swaps are periodically used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and a ceiling price (collar) for expected future oil and natural-gas sales. Derivative instruments are also used to manage commodity-price risk inherent in customer price requirements and to fix margins on the future sale of natural gas and NGLs from the Company’s leased storage facilities (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 15—Accumulated Other Comprehensive Income (Loss).


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

6. Derivative Instruments (Continued)

Oil and Natural-Gas Production/Processing Derivative Activities  The oil prices listed below are a combination of New York Mercantile Exchange (NYMEX) West Texas Intermediate and Intercontinental Exchange, Inc. (ICE) Brent Blend prices. The natural-gas prices listed below are NYMEX Henry Hub prices. The NGLs prices listed below are Oil Price Information Services prices. The following is a summary of the Company’s derivative instruments related to oil and natural-gas production/processing derivative activities at March 31, 2016:
 
2016 Settlement
Oil
 
Three-Way Collars (MBbls/d)
83

Average price per barrel
 
Ceiling sold price (call)
$
63.82

Floor purchased price (put)
$
54.46

Floor sold price (put)
$
42.77

Natural Gas
 
Fixed-Price Contracts (thousand MMBtu/d)
43

Average price per MMBtu
$
2.24

NGLs
 
Fixed-Price Contracts (MBbls/d)
4

Average price per barrel
$
12.93

__________________________________________________________________
MBbls/d—thousand barrels per day
MMBtu/d—million British thermal units per day
MMBtu—million British thermal units

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

Marketing and Trading Derivative Activities  The Company had financial derivative transactions with notional volumes of natural gas totaling 4 billion cubic feet (Bcf) at March 31, 2016, and 8 Bcf at December 31, 2015, that were entered into to mitigate commodity-price risk related to fixed-price purchase and sales contracts and storage activity.


11
Table of Contents

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). The Company used proceeds from its $3.0 billion March 2016 Senior Notes issuances to purchase and retire $1.25 billion of its $2.0 billion 6.375% Senior Notes due September 2017 in April 2016 pursuant to a tender offer and to redeem the $1.750 billion 5.950% Senior Notes due September 2016 in May 2016. The outstanding interest-rate swaps with a notional amount of $1.7 billion due prior to or at September 2021 will manage interest-rate risk associated with the potential refinancing of the Company’s $900 million Senior Notes due 2019 and the Zero-Coupon Senior Notes due 2036 (Zero Coupons), should the Zero Coupons be put to the Company prior to the swap termination dates. At the next put date in October 2016, the accreted value of the Zero Coupons will be $839 million. See Note 8—Debt and Interest Expense. Depending on market conditions, liability-management actions, or other factors, the Company may enter into offsetting interest-rate swap positions, or settle or amend, certain or all of the currently outstanding interest-rate swaps. 
In February 2016, in exchange for amended terms with certain counterparties, the Company modified the mandatory termination dates from 2021 to 2018 and, in some cases, the related fixed interest rates on interest-rate swaps with an aggregate notional principal amount of $500 million. Additionally, an interest-rate swap agreement was settled in March 2016, resulting in a cash payment of $193 million.
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 March 31, 2016: 
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%
$
500

 
 
September 2016 – 2046
 
September 2018
 
6.559%
$
300

 
 
September 2016 – 2046
 
September 2020
 
6.509%
$
450

 
 
September 2017 – 2047
 
September 2018
 
6.445%
$
100

 
 
September 2017 – 2047
 
September 2020
 
6.891%
$
250

 
 
September 2017 – 2047
 
September 2021
 
6.570%


12
Table of Contents

ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

6. Derivative Instruments (Continued)

Effect of Derivative Instruments—Balance Sheet  The following summarizes the fair value of the Company’s derivative instruments:
 
 
Gross Derivative Assets
 
Gross Derivative Liabilities
millions
 
March 31,
 
December 31,
 
March 31,
 
December 31,
Balance Sheet Classification
 
2016
 
2015
 
2016
 
2015
Commodity derivatives
 
 
 
 
 
 
 
 
Other current assets
 
$
322

 
$
462

 
$
(116
)
 
$
(177
)
Other assets
 
7

 
8

 
—

 
—

Accrued expenses
 
—

 
—

 
(2
)
 
(3
)
 
 
329

 
470

 
(118
)
 
(180
)
Interest-rate derivatives
 
 
 
 
 
 
 
 
Other current assets
 
2

 
2

 
—

 
—

Other assets
 
20

 
54

 
—

 
—

Accrued expenses
 
—

 
—

 
(90
)
 
(54
)
Other liabilities
 
—

 
—

 
(1,550
)
 
(1,488
)
 
 
22

 
56

 
(1,640
)
 
(1,542
)
Total derivatives
 
$
351

 
$
526

 
$
(1,758
)
 
$
(1,722
)

Effect of Derivative Instruments—Statement of Income  The following summarizes gains and losses related to derivative instruments:
millions
 
Three Months Ended 
 March 31,
Classification of (Gain) Loss Recognized
 
2016
 
2015
Commodity derivatives
 
 
 
 
Gathering, processing, and marketing sales (1)
 
$
2

 
$
—

(Gains) losses on derivatives, net
 
(28
)
 
(53
)
Interest-rate derivatives
 
 
 
 
(Gains) losses on derivatives, net
 
325

 
205

Total (gains) losses on derivatives, net
 
$
299

 
$
152

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


13
Table of Contents

ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

6. Derivative Instruments (Continued)

Credit-Risk Considerations  The financial integrity of exchange-traded contracts, which are subject to nominal credit risk, is assured by NYMEX or ICE through systems of financial safeguards and transaction guarantees. Over-the-counter traded swaps, options, and futures contracts expose the Company to counterparty credit risk. The Company monitors the creditworthiness of its counterparties, establishes credit limits according to the Company’s credit policies and guidelines, and assesses the impact on the fair value of its counterparties’ creditworthiness. The Company has the ability to require cash collateral or letters of credit to mitigate its credit-risk exposure.
The Company has netting agreements with financial institutions that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities, and routinely exercises its contractual right to offset gains and losses when settling with derivative counterparties. In addition, the Company has setoff agreements with certain financial institutions that may be exercised in the event of default and provide for contract termination and net settlement across derivative types. At March 31, 2016, $238 million of the Company’s $1.758 billion gross derivative liability balance, and at December 31, 2015, $347 million of the Company’s $1.722 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 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 a level that is below investment grade. In February 2016, Moody’s Investors Service (Moody’s) downgraded the Company’s long-term debt credit rating from “Baa2” to “Ba1,” which is below investment grade. The downgrade triggered credit-risk-related features with certain derivative counterparties and required the Company to post collateral under its derivative instruments. The amount of cash posted as collateral pursuant to the contractual requirements applicable to derivative instruments with financial institutions was $420 million at March 31, 2016, and $58 million at December 31, 2015. No counterparties have requested termination or full settlement of derivative positions. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $1.1 billion (net of collateral) at March 31, 2016, and $1.3 billion (net of collateral) at December 31, 2015.


14
Table of Contents

ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

6. Derivative Instruments (Continued)

Fair Value  Fair value of futures contracts is based on unadjusted quoted prices in active markets for identical assets or liabilities, which represent Level 1 inputs. Valuations of physical-delivery purchase and sale agreements, over-the-counter financial swaps, and commodity option collars are based on similar transactions observable in active markets and industry-standard models that primarily rely on market-observable inputs. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. Inputs used to estimate the fair value of swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and, for Black-Scholes option valuations, discount factors and implied market volatility.
The following summarizes the fair value of the Company’s derivative assets and liabilities by input level within the fair-value hierarchy:
millions
 
 
 
 
 
 
 
 
 
 
 
March 31, 2016
Level 1
 
Level 2
 
Level 3
 
Netting (1)
 
Collateral
 
Total
Assets
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
1

 
$
328

 
$
—

 
$
(116
)
 
$
(1
)
 
$
212

Interest-rate derivatives
—

 
22

 
—

 
—

 
—

 
22

Total derivative assets
$
1

 
$
350

 
$
—

 
$
(116
)
 
$
(1
)
 
$
234

Liabilities
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
—

 
$
(118
)
 
$
—

 
$
116

 
$
—

 
$
(2
)
Interest-rate derivatives
—

 
(1,640
)
 
—

 
—

 
421

 
(1,219
)
Total derivative liabilities
$
—

 
$
(1,758
)
 
$
—

 
$
116

 
$
421

 
$
(1,221
)
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2015
 
 
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
10

 
$
460

 
$
—

 
$
(178
)
 
$
(8
)
 
$
284

Interest-rate derivatives
—

 
56

 
—

 
—

 
—

 
56

Total derivative assets
$
10

 
$
516

 
$
—

 
$
(178
)
 
$
(8
)
 
$
340

Liabilities
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
(1
)
 
$
(179
)
 
$
—

 
$
178

 
$
—

 
$
(2
)
Interest-rate derivatives
—

 
(1,542
)
 
—

 
—

 
58

 
(1,484
)
Total derivative liabilities
$
(1
)
 
$
(1,721
)
 
$
—

 
$
178

 
$
58

 
$
(1,486
)
 __________________________________________________________________
(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.

15
Table of Contents

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 WGP 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. 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 Sheets.

Equity Component  Unless settled earlier at the holder’s option, each purchase contract has a mandatory settlement date of June 7, 2018. Anadarko has a right to elect to issue and deliver shares of Anadarko Petroleum Corporation common stock (APC shares) in lieu of delivering WGP common units at settlement. The Company will deliver not more than 0.8591 WGP common units and not less than 0.7159 WGP common units (or a computed number of APC shares) per TEU on the settlement date, subject to adjustment, at the settlement rate based upon the applicable market value of WGP common units (or APC shares).

Debt Component Each senior amortizing note has an initial principal amount of $10.95 and bears interest at 1.50% per year. On September 7, 2015, Anadarko began paying 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 Activity  The following summarizes the Company’s debt activity, after eliminating the effect of intercompany transactions, during the three months ended March 31, 2016:
 
Carrying Value
 
 
millions
WES
 
WGP (1)
 
Anadarko (2)
 
Anadarko Consolidated
 
Description
Balance at December 31, 2015
$
2,691

 
$
—

 
$
12,957

 
$
15,648

 
 
Issuances
—

 
—

 
794

 
794

 
4.850% Senior Notes due 2021
 
—

 
—

 
1,088

 
1,088

 
5.550% Senior Notes due 2026
 
—

 
—

 
1,088

 
1,088

 
6.600% Senior Notes due 2046
Borrowings
—

 
—

 
1,350

 
1,350

 
364-Day Facility
 
330

 
—

 
—

 
330

 
WES RCF
 
—

 
28

 
—

 
28

 
WGP RCF
Repayments
—

 
—

 
(1,350
)
 
(1,350
)
 
364-Day Facility
 
—

 
—

 
(250
)
 
(250
)
 
Commercial paper notes, net
 
—

 
—

 
(8
)
 
(8
)
 
TEUs - senior amortizing notes
Other, net
—

 
—

 
13

 
13

 
Amortization of discounts, premiums, and debt issuance costs
Balance at March 31, 2016
$
3,021

 
$
28

 
$
15,682

 
$
18,731

 
 
__________________________________________________________________
(1) 
Excludes WES.
(2) 
Excludes WES and WGP.



16
Table of Contents

ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

8. Debt and Interest Expense (Continued)

Debt  The Company’s outstanding debt, excluding the capital lease obligation and any borrowings under the WGP revolving credit facility, is senior unsecured. The following summarizes the Company’s outstanding debt after eliminating the effect of intercompany transactions:
millions
WES
 
WGP (1)
 
Anadarko (2)
 
Anadarko Consolidated
March 31, 2016
 
 
 
 
 
 
 
Total borrowings at face value
$
3,050

 
$
28

 
$
17,333

 
$
20,411

Net unamortized discounts, premiums, and debt issuance costs (3)
(29
)
 
—

 
(1,651
)
 
(1,680
)
Total borrowings
3,021

 
28

 
15,682

 
18,731

Capital lease obligation
—

 
—

 
20

 
20

Less short-term debt
—

 
—

 
3,025

 
3,025

Total long-term debt
$
3,021

 
$
28

 
$
12,677

 
$
15,726

 
 
 
 
 
 
 
 
December 31, 2015
 
 
 
 
 
 
 
Total borrowings at face value
$
2,720

 
$
—

 
$
14,592

 
$
17,312

Net unamortized discounts, premiums, and debt issuance costs (3)
(29
)
 
—

 
(1,635
)
 
(1,664
)
Total borrowings
2,691

 
—

 
12,957

 
15,648

Capital lease obligation
—

 
—

 
20

 
20

Less short-term debt
—

 
—

 
32

 
32

Total long-term debt
$
2,691

 
$
—

 
$
12,945

 
$
15,636

__________________________________________________________________
(1) 
Excludes WES.
(2) 
Excludes WES and WGP.
(3) 
Unamortized discounts, premiums, and debt issuance costs are amortized over the term of the related debt. Debt issuance costs related to revolving credit facilities are included in other current assets and other assets on the Company’s Consolidated Balance Sheets.

Anadarko’s $1.750 billion 5.950% Senior Notes due September 2016 and $1.25 billion of the Company’s $2.0 billion 6.375% Senior Notes due September 2017 were classified as short-term debt on the Company’s Consolidated Balance Sheet at March 31, 2016. The Company used proceeds from its $3.0 billion March 2016 Senior Notes issuances to purchase and retire $1.25 billion of its $2.0 billion Senior Notes in April 2016 pursuant to a tender offer and to redeem the $1.750 billion Senior Notes in May 2016.
Anadarko’s Zero Coupons can be put to the Company in October of each year, in whole or in part, for the then-accreted value, which will be $839 million at the next put date in October 2016. Anadarko’s Zero Coupons were classified as long-term debt on the Company’s Consolidated Balance Sheet at March 31, 2016, as the Company has the ability and intent to refinance these obligations using long-term debt, should the put be exercised.

Fair Value  The Company uses a market approach to determine the fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. The estimated fair value of the Company’s total borrowings was $18.9 billion at March 31, 2016, and $15.7 billion at December 31, 2015.


17
Table of Contents

ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

8. Debt and Interest Expense (Continued)

Anadarko Revolving Credit Facilities and Commercial Paper Program  Anadarko has a $3.0 billion five-year senior unsecured revolving credit facility maturing in January 2021 (Five-Year Facility). In addition, in January 2016 the Company replaced its previous $2.0 billion 364-day senior unsecured revolving credit facility with a new $2.0 billion 364-day senior unsecured revolving credit facility (364-Day Facility), on identical terms, that will mature in January 2017. At March 31, 2016, the Company had no outstanding borrowings under the Five-Year Facility or the 364-Day Facility and was in compliance with all covenants contained therein.
In January 2015, the Company initiated a commercial paper program, which allows for 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 may vary, but may not exceed 397 days. In February 2016, Moody’s downgraded the Company’s commercial paper program credit rating, which essentially eliminated the Company’s access to the commercial paper market. As a result, the Company has not issued commercial paper notes since the downgrade. At March 31, 2016, the Company had no outstanding borrowings under the commercial paper program.

WES and WGP Borrowings  At March 31, 2016, WES was in compliance with all covenants contained in its five-year $1.2 billion senior unsecured revolving credit facility maturing in February 2019 (WES RCF), which is expandable to $1.5 billion. At March 31, 2016, WES had outstanding borrowings under its RCF of $630 million at an interest rate of 1.74%, had outstanding letters of credit of $5 million, and had available borrowing capacity of $565 million.
In March 2016, WGP entered into a three-year $250 million senior secured revolving credit facility maturing in March 2019 (WGP RCF), which is expandable to $500 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions. Obligations under the WGP RCF are secured by a first priority lien on all of WGP’s assets (not including the consolidated assets of WES), as well as all equity interests owned by WGP. Borrowings under the WGP RCF bear interest at LIBOR (with a floor of 0%), plus applicable margins ranging from 2.00% to 2.75% depending on WGP’s consolidated leverage ratio, or at a base rate equal to the greatest of (i) the prime rate, (ii) the federal funds rate plus 0.50%, or (iii) LIBOR plus 1.00%, in each case plus applicable margins ranging from 1.00% to 1.75% based upon WGP’s consolidated leverage ratio. At March 31, 2016, WGP was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $28 million at an interest rate of 2.69%, and had available borrowing capacity of $222 million.

Interest Expense  The following summarizes interest expense:
 
Three Months Ended 
 March 31,
millions
2016
 
2015
Debt and other
$
258

 
$
254

Capitalized interest
(38
)
 
(38
)
Total interest expense
$
220

 
$
216



18
Table of Contents

ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

9. Income Taxes

The following summarizes income tax expense (benefit) and effective tax rates:
 
Three Months Ended 
 March 31,
millions except percentages
2016
 
2015
Income tax expense (benefit)
$
(383
)
 
$
(1,392
)
Income (loss) before income taxes
(1,381
)
 
(4,628
)
Effective tax rate
28
%
 
30
%

The Company reported a loss before income taxes for the three months ended March 31, 2016 and 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 months ended March 31, 2016 and 2015, was primarily attributable to non-deductible Algerian exceptional profits tax for Algerian income tax purposes, the tax impact from foreign operations, and net changes in uncertain tax positions.
At March 31, 2016, the Company’s Consolidated Balance Sheet included $1.1 billion of income taxes receivable presented in accounts receivable—others.

10. Conveyance of Future Hard Minerals Royalty Revenues

During the first quarter of 2016, the Company conveyed a limited-term nonparticipating royalty interest in certain of its coal and trona leases to a third party for $413 million, net of transaction costs. Such conveyance entitles the third party to receive up to $553 million in future royalty revenue over a period of not less than 10 years and not greater than 15 years. Additionally, such third party is entitled to receive 3% of the aggregate royalties earned during the first 10 years between $800 million and $900 million and 4% of the aggregate royalties earned during the first 10 years that exceed $900 million. Generally, such third party relies solely on the royalty payments to recover its investment and, as such, has the risk of the royalties not being sufficient to recover its investment over the term of the conveyance.
Proceeds from this transaction have been accounted for as deferred revenues and are included in accrued expenses and other long-term liabilities on the Company’s Consolidated Balance Sheet. The deferred revenues will be amortized to other revenues, included in gains (losses) on divestitures and other, net on a unit-of-revenue basis over the term of the agreement. During the first quarter of 2016, the Company amortized $12 million of deferred revenues as a result of this agreement. Proceeds from the transaction and payments to the third party are reported in financing activities in the Company’s Consolidated Statement of Cash Flows.
The third party will receive the first payment for royalties in September 2016. The specified future amounts that the third party expects to receive and the payment timing are subject to change based upon the actual royalties received by the Company during the term of the conveyance. The following summarizes the future amounts, prior to the 3% to 4% of any excess described above, that the third party expects to receive:
millions
 
2016
$
25

2017
50

2018
50

2019
52

2020
56

Later years
320

Total
$
553



19
Table of Contents

ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

11. 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, 2015.

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.
Numerous Deepwater Horizon event-related civil lawsuits were filed against BP and other parties, including the Company. Generally, the plaintiffs sought actual damages, punitive damages, declaratory judgment, and/or injunctive relief. This litigation was consolidated into a federal Multidistrict Litigation (MDL) action pending before Judge Carl Barbier in the U.S. District Court for the Eastern District of Louisiana in New Orleans, Louisiana (Louisiana District Court).

BP Consent Decree In July 2015, BP announced a settlement agreement in principle with the U.S. Department of Justice (DOJ) and certain states and local government entities regarding essentially all of the outstanding claims against BP related to the Deepwater Horizon event (BP Settlement) and, in October 2015, lodged a proposed consent decree with the Louisiana District Court. In April 2016, the Louisiana District Court approved the consent decree. As a result of the BP Settlement and approval of the consent decree, all liability relating to OPA-related environmental costs was resolved and all NRD claims and claims by the United States and the Gulf states impacted by the event relating to the MDL action were dismissed. For any remaining claims relating to the MDL action, the Company is fully indemnified by BP against any losses pursuant to the Settlement Agreement. For additional disclosure related to the Deepwater Horizon events, see Note 15—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, 2015.

Penalties and Fines  In December 2010, the DOJ, on behalf of the United States, filed a civil lawsuit in the 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. After previously finding that Anadarko, as a nonoperating investor in the Macondo well, was not culpable with respect to the Deepwater Horizon events, the Louisiana District Court found Anadarko liable for civil penalties under Section 311 of the CWA as a working-interest owner in the Macondo well and entered a judgment of $159.5 million in December 2015. Neither party appealed the decision and the Company paid the penalty in the first quarter of 2016.


20
Table of Contents

ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

12. Restructuring Charges

In the first quarter of 2016, the Company initiated a workforce reduction program to align the size and composition of Anadarko’s workforce with the Company’s expected future operating and capital plans. Employee notifications related to the workforce reduction program were substantially complete by March 31, 2016, and all restructuring charges will be recognized in 2016, with the exception of $10 million of expense for retirement benefits expected to be recognized in the first quarter of 2017. The following summarizes the total expected restructuring charges and the amounts expensed during the first quarter of 2016, which were included in general and administrative expenses in the Company’s Consolidated Statement of Income:
millions
Total Expected Costs
 
Three Months Ended March 31, 2016
Costs by category
 
 
 
Cash severance
$
154

 
$
131

Retirement benefits (1)
203

 
49

Share-based compensation
32

 
23

Total
$
389

 
$
203

__________________________________________________________________
(1) 
Includes termination benefits, curtailments, and settlements. There were no settlements recognized during the three months ended March 31, 2016. See Note 13—Pension Plans and Other Postretirement Benefits.

The following summarizes the changes in the cash severance-related liability included in accounts payable on the Company’s Consolidated Balance Sheet:
millions
2016
Balance at January 1
$
—

Accruals
131

Payments
(79
)
Balance at March 31
$
52



21
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

13. Pension Plans and Other Postretirement Benefits

The Company has contributory and non-contributory defined-benefit pension plans, which include both qualified and supplemental plans. The Company also provides certain health care and life insurance benefits for certain retired employees. Retiree health care benefits are funded by contributions from the retiree and, in certain circumstances, contributions from the Company. The Company’s retiree life insurance plan is noncontributory. The following summarizes the Company’s pension and other postretirement benefit cost:
 
Pension Benefits
 
Other Benefits
millions
2016
 
2015
 
2016
 
2015
Three Months Ended March 31
 
 
 
 
 
 
 
Service cost
$
26

 
$
30

 
$
1

 
$
3

Interest cost
26

 
25

 
3

 
4

Expected return on plan assets
(27
)
 
(27
)
 
—

 
—

Amortization of net actuarial loss (gain)
8

 
13

 
—

 
—

Amortization of net prior service cost (credit)
—

 
—

 
(6
)
 
—

Termination benefits expense
44

 
—

 
—

 
—

Curtailment expense
8

 
—

 
(3
)
 
—

Net periodic benefit cost
$
85

 
$
41

 
$
(5
)
 
$
7


In the first quarter of 2016, the Company initiated a workforce reduction program that resulted in a remeasurement of its pension and other postretirement benefit obligations. The Company recognized curtailment expense for both the curtailment-related increase in the benefit obligation and a proportionate share of prior service cost from other comprehensive income (loss). The Company also recognized termination benefits expense related to benefit enhancements to certain employees affected by the workforce reduction program. In addition, the remeasurement resulted in increases in the benefit obligation of $146 million for the pension benefit plans and $26 million for the other postretirement benefit plans, with a corresponding decrease in other comprehensive income.
The Company expects to contribute an additional $82 million in 2016 and $23 million in 2017 to unfunded pension plans related to the workforce reduction program. See Note 12—Restructuring Charges.


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

14. 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, TEUs, and WES Series A Preferred units, 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 
 March 31,
millions except per-share amounts
2016
 
2015
Net income (loss)
 
 
 
Net income (loss) attributable to common stockholders
$
(1,034
)
 
$
(3,268
)
Income (loss) effect of TEUs
(1
)
 
—

Less distributions on participating securities
—

 
1

Basic
$
(1,035
)
 
$
(3,269
)
Diluted
$
(1,035
)
 
$
(3,269
)
Shares
 
 
 
Average number of common shares outstanding—basic
509

 
507

Average number of common shares outstanding—diluted
509

 
507

Excluded due to anti-dilutive effect
10

 
11

Net income (loss) per common share
 
 
 
Basic
$
(2.03
)
 
$
(6.45
)
Diluted
$
(2.03
)
 
$
(6.45
)

23
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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

15. 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, 2015
$
(42
)
 
$
(341
)
 
$
(383
)
Other comprehensive income (loss), before reclassifications
—

 
(105
)
 
(105
)
Reclassifications to Consolidated Statement of Income
2

 
(5
)
 
(3
)
Balance at March 31, 2016
$
(40
)
 
$
(451
)
 
$
(491
)

16. Noncontrolling Interests

WGP, a publicly traded consolidated subsidiary, is a limited partnership formed by Anadarko to own partnership interests in WES. At March 31, 2016, 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 formed by Anadarko to acquire, own, develop, and operate midstream assets. During the three months ended March 31, 2016, WES issued 14 million Series A Preferred units to private investors and raised net proceeds of $440 million, and issued 1.3 million common units to the Company. Proceeds were used to acquire interests in Springfield Pipeline LLC from the Company. In April 2016, WES issued an additional eight million Series A Preferred units to private investors, pursuant to the full exercise of an option granted in connection with the initial issuance, and raised net proceeds of $248 million.
Class C units issued to Anadarko will receive quarterly distributions in the form of additional Class C units until the end of 2017, unless WES elects to convert the units to common units earlier or Anadarko elects to extend the conversion date. WES distributed 324 thousand Class C units to Anadarko during the three months ended March 31, 2016, and 498 thousand Class C units to Anadarko during 2015. During 2015, WES issued approximately 874 thousand common units to the public and raised net proceeds of $57 million.
At March 31, 2016, WGP’s ownership interest in WES consisted of a 31.5% limited partner interest, the entire 1.6% general partner interest, and all of the WES incentive distribution rights. At March 31, 2016, Anadarko also owned an 8.7% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining 58.2% limited partner interest in WES was owned by the public.


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

17. Variable Interest Entities

Consolidated VIEs The Company determined that the partners in WGP and WES with equity at risk lack the power, through voting rights or similar rights, to direct the activities that most significantly impact WGP’s and WES’s economic performance; therefore, WGP and WES are considered VIEs. Anadarko, through its ownership of the general partner interest in WGP, has the power to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to WGP and WES, therefore Anadarko is considered the primary beneficiary and consolidates WGP and WES. See Note 16—Noncontrolling Interests for additional information on WGP and WES.

Assets and Liabilities of VIEs The assets of WGP and WES cannot be used by Anadarko for general corporate purposes and are both included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets. The carrying amounts of liabilities related to WGP and WES for which the creditors do not have recourse to other assets of the Company are both included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets.
All outstanding debt for WES at March 31, 2016, and December 31, 2015, including any borrowings under the WES RCF, is recourse to WES’s general partner, which in turn has been indemnified in certain circumstances by certain wholly owned subsidiaries of the Company for such liabilities. All outstanding debt for WGP at March 31, 2016, and December 31, 2015, including any borrowings under the WGP RCF, is recourse to WGP’s general partner, which is a wholly owned subsidiary of the Company. See Note 8—Debt and Interest Expense for additional information on WGP and WES long-term debt balances.

VIE Financing WGP’s sources of liquidity include borrowings under its RCF and distributions from WES. WES’s sources of liquidity include cash and cash equivalents, cash flows generated from operations, interest income from a note receivable from Anadarko as discussed below, borrowings under its RCF, the issuance of additional partnership units, or debt offerings. See Note 8—Debt and Interest Expense and Note 16—Noncontrolling Interests for additional information on WGP and WES financing activity.

Financial Support Provided to VIEs Concurrent with the closing of its May 2008 initial public offering, WES loaned the Company $260 million in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The related interest income for WES was $4 million for the three months ended March 31, 2016 and 2015. The note receivable and related interest income is eliminated in consolidation.
In March 2015, WES acquired the Company’s interest in Delaware Basin JV Gathering LLC. The acquisition was financed using a deferred purchase price obligation which requires a cash payment from WES to the Company due on March 31, 2020. The net present value of this obligation was $193 million at March 31, 2016, and $189 million at December 31, 2015.
In order to reduce WES’s exposure to a majority of the commodity-price risk inherent in certain of their contracts, Anadarko has commodity price swap agreements in place with WES expiring in 2016. WES has recorded a capital contribution from Anadarko in its Consolidated Statement of Equity and Partners’ Capital for the amount by which the swap price exceeds the applicable market price. WES recorded a $4 million capital contribution from Anadarko for the three months ended March 31, 2016, and a capital contribution of zero for the three months ended March 31, 2015.


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

18. Supplemental Cash Flow Information

The following summarizes cash paid (received) for interest and income taxes, as well as non-cash investing and financing activities:
 
Three Months Ended 
 March 31,
millions
2016
 
2015
Cash paid (received)
 
 
 
Interest, net of amounts capitalized (1)
$
299

 
$
1,532

Income taxes, net of refunds
(8
)
 
(5
)
Non-cash investing activities
 
 
 
Fair value of properties and equipment from non-cash transactions
$
—

 
$
54

Asset retirement cost additions
27

 
63

Accruals of property, plant, and equipment
623

 
1,080

Net liabilities assumed (divested) in acquisitions and divestitures
—

 
19

Non-cash investing and financing activities
 
 
 
Floating production, storage, and offloading vessel construction period obligation
$
2

 
$
25

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

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

19. 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 oil, condensate, natural gas, 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, condensate, 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; gains (losses) on divestitures, net; 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 (loss) attributable to noncontrolling interests. During the periods presented, items not related to the Company’s normal operations included restructuring charges related to the workforce reduction program included in general and administrative expenses, other operating expenses such as 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 gains (losses) on divestitures, net and exploration expense as they are not indicators 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 (loss) attributable to noncontrolling interests is excluded from the Company’s measure of Adjusted EBITDAX because it represents earnings that are not attributable to the Company’s common stockholders.
Management believes 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 
 March 31,
millions
2016
 
2015
Income (loss) before income taxes
$
(1,381
)
 
$
(4,628
)
(Gains) losses on divestitures, net
(2
)
 
334

Exploration expense
126

 
1,083

DD&A
1,149

 
1,256

Impairments
16

 
2,783

Interest expense
220

 
216

Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives
404

 
243

Restructuring charges
203

 
—

Other operating expense
1

 
4

Tronox-related contingent loss
—

 
5

Certain other nonoperating items
—

 
22

Less net income (loss) attributable to noncontrolling interests
36

 
32

Consolidated Adjusted EBITDAX
$
700

 
$
1,286


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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

19. 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 March 31, 2016
 
 
 
 
 
 
 
 
 
Sales revenues
$
711

 
$
125

 
$
798

 
$
—

 
$
1,634

Intersegment revenues
601

 
302

 
(663
)
 
(240
)
 
—

Other
—

 
—

 
—

 
38

 
38

Total revenues and other (1)
1,312

 
427

 
135

 
(202
)
 
1,672

Operating costs and expenses (2)
773

 
183

 
176

 
(89
)
 
1,043

Net cash from settlement of commodity derivatives
—

 
—

 
—

 
(103
)
 
(103
)
Other (income) expense, net
—

 
—

 
—

 
—

 
—

Net income (loss) attributable to noncontrolling interests
—

 
36

 
—

 
—

 
36

Total expenses and other
773

 
219

 
176

 
(192
)
 
976

Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement
—

 
—

 
4

 
—

 
4

Adjusted EBITDAX
$
539

 
$
208

 
$
(37
)
 
$
(10
)
 
$
700

 
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2015
 
 
 
 
 
 
 
 
 
Sales revenues
$
1,070

 
$
174

 
$
1,341

 
$
—

 
$
2,585

Intersegment revenues
1,117

 
302

 
(1,191
)
 
(228
)
 
—

Other
—

 
—

 
—

 
70

 
70

Total revenues and other (1)
2,187

 
476

 
150

 
(158
)
 
2,655

Operating costs and expenses (2)
1,002

 
240

 
198

 
(37
)
 
1,403

Net cash from settlement of commodity derivatives
—

 
—

 
—

 
(90
)
 
(90
)
Other (income) expense, net (3)
—

 
—

 
—

 
25

 
25

Net income (loss) attributable to noncontrolling interests
—

 
32

 
—

 
—

 
32

Total expenses and other
1,002

 
272

 
198

 
(102
)
 
1,370

Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement
—

 
—

 
1

 
—

 
1

Adjusted EBITDAX
$
1,185

 
$
204

 
$
(47
)
 
$
(56
)
 
$
1,286

 __________________________________________________________________
(1) 
Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.
(2) 
Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and other operating expense since these expenses are excluded from Adjusted EBITDAX.
(3) 
Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.

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

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

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

•
the Company’s assumptions about energy markets
•
production and sales volume levels
•
levels of oil, natural-gas, and natural-gas liquids (NGLs) reserves
•
operating results
•
competitive conditions
•
technology
•
availability of capital resources, levels of capital expenditures, and other contractual obligations
•
supply and demand for, the price of, and the commercialization and transporting of oil, natural gas, NGLs, and other products or services
•
volatility in the commodity-futures market
•
weather
•
inflation
•
availability of goods and services, including unexpected changes in costs
•
drilling 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
•
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

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Table of Contents

•
volatility in the securities, capital, or credit markets and related risks such as general credit, liquidity, and interest-rate risk
•
the Company’s ability to successfully monetize select assets, repay or refinance its debt, 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, 2015, this Form 10-Q, and in the Company’s other public filings, press releases, and discussions with Company management
The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this Form 10-Q in Part I, Item 1; the information set forth in the Risk Factors under Part II, Item 1A; the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in Part II, Item 8 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2015; 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, 2015.

OUTLOOK

During 2015, the oil and natural-gas industry experienced a significant decrease in commodity prices driven by a global supply/demand imbalance for oil and an oversupply of natural gas in the United States. The decline in commodity prices has continued into 2016 and low commodity prices may exist for an extended period. The Company’s revenues, operating results, cash flows from operations, capital spending, and future growth rates are highly dependent on the global commodity-price markets, which affect the value the Company receives from its sales of oil, natural gas, and NGLs.
The Company has continued its disciplined and focused approach in 2016 by emphasizing value over growth, preserving and building value through capital allocation, enhancing operational efficiencies, and continuing an active monetization program. Further, in the first quarter of 2016, the Company initiated a workforce reduction program to align the size and composition of Anadarko’s workforce with the Company’s expected future operating and capital plans. Employee notifications related to the workforce reduction program were substantially complete by March 31, 2016, and all of the $389 million of expected restructuring charges will be recognized in 2016, with the exception of $10 million of expense for retirement benefits expected to be recognized in the first quarter of 2017.
The Company estimates a 2016 capital spending range of $3.1 billion to $3.3 billion, including approximately $450 million to $490 million for Western Gas Partners, LP (WES), a publicly traded consolidated subsidiary, excluding any acquisitions made by WES. The Company has currently allocated approximately 65% of its 2016 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 2016 capital spending by area to be approximately 40% for the U.S. onshore region and Alaska, 20% for the Gulf of Mexico, 20% for Midstream and other (including WES), and 20% for International.
The Company will continue to evaluate the oil and natural-gas price environments and may adjust its capital spending plans to maintain the appropriate liquidity and financial flexibility. Anadarko expects that its 2016 capital expenditures will be within its cash flows from operations and asset monetizations. As of the time of filing this Form 10-Q, the Company closed monetizations totaling $1.3 billion in 2016. These monetizations continue Anadarko’s track record of actively managing its portfolio and reaffirm the Company’s commitment toward strengthening its balance sheet.


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Liquidity  As of March 31, 2016, Anadarko had $2.9 billion of cash on hand plus $5.0 billion of borrowing capacity under its revolving credit facilities.
The Company used proceeds from its $3.0 billion March 2016 Senior Notes issuances to purchase and retire $1.25 billion of its $2.0 billion 6.375% Senior Notes due September 2017 in April 2016 pursuant to a tender offer and to redeem the $1.750 billion 5.950% Senior Notes due September 2016 in May 2016.
Anadarko believes that its cash on hand, anticipated operating cash flows, and proceeds from expected future asset monetizations will be sufficient to fund the Company’s projected 2016 operational and capital programs. In response to the current commodity price environment, the Board of Directors (Board) decreased the quarterly dividend from $0.27 per share to $0.05 per share in February 2016. On an annualized basis, the dividend decrease and the workforce reduction program (without consideration for restructuring charges) are expected to have the effect of providing approximately $800 million of available cash to enhance the Company’s operations and financial flexibility. In April 2016, Anadarko received cash of $881 million from a tax refund related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback. Further, Anadarko enters into strategic derivative positions to reduce commodity-price risk and increase the predictability of cash flows. At March 31, 2016, derivative positions covered 27% of Anadarko’s anticipated oil sales volumes, 3% of its anticipated NGLs sales volumes, and 2% of its anticipated natural-gas sales volumes for 2016. These instruments had a fair value of $200 million as of March 31, 2016. See Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. Anadarko believes that the actions taken to enhance the Company’s liquidity position coupled with its asset portfolio and operating and financial performance provide the necessary financial flexibility to fund the Company’s current and long-term operations.

Potential for Future Impairments  During 2015, the Company recognized significant impairments of proved oil and gas and midstream properties and impairments of unproved oil and gas properties, primarily as a result of lower forecasted commodity prices and related changes to the Company’s drilling plans. While commodity prices continued to decline during the first quarter of 2016, the Company did not recognize any material impairments. At March 31, 2016, the Company’s estimate of undiscounted future cash flows attributable to a certain depletion group with a net book value of approximately $2.1 billion indicated that the carrying amount was expected to be recovered; however, this depletion group may be at risk for impairment if the estimates of future cash flows decline. The Company estimates that, if this depletion group becomes impaired in a future period, the Company could recognize non-cash impairments in that period in excess of $1.0 billion. It is also reasonably possible that prolonged low or further declines in commodity prices, changes to the Company’s drilling plans in response to lower prices, or increases in drilling or operating costs could result in additional impairments.
Anadarko had approximately $5.4 billion of goodwill at March 31, 2016, allocated to the following reporting units: $4.9 billion to oil and gas exploration and production, $414 million to WES gathering and processing, $5 million to WES transportation, and $33 million to other gathering and processing. Goodwill is tested annually in October (or more frequently as circumstances dictate). Although commodity prices have continued to decline in 2016, as of March 31, 2016, the estimated fair value of the oil and gas reporting unit exceeded the carrying value by more than 15% and the other reporting units were not at risk of impairment. However, it is reasonably possible that prolonged low or further declines in commodity prices, decreases in proved reserves, changes in exploration or development plans, significant property impairments, increases in operating or drilling costs, significant changes in regulations, or other negative changes to the economic environment in which Anadarko operates could result in a further reduction in the fair value of the reporting units and increase the potential for a future impairment of goodwill.


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Table of Contents

OVERVIEW

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

Significant operating and financial activities for the first quarter of 2016 include the following:

Overall
•
Anadarko’s first-quarter sales volumes averaged 827 thousand barrels of oil equivalent per day (MBOE/d), representing an 11% decrease from the first quarter of 2015, primarily due to a decrease in natural-gas sales volumes.
•
The Company’s overall sales-volume product mix increased to 53% liquids in the first quarter of 2016 compared to 51% in the first quarter of 2015.
•
The Company initiated a workforce reduction program and recognized related expenses of $203 million in the first quarter of 2016, with total program expenses expected to be $389 million. 
•
As of the time of filing this Form 10-Q, the Company closed monetizations totaling $1.3 billion, including the sale of Anadarko’s interest in Springfield Pipeline LLC to WES and the Company’s conveyance of a limited-term nonparticipating royalty interest in certain of its coal and trona leases to a third party.
U.S. Onshore
•
First-quarter liquids sales volumes decreased by 33 MBbls/d, representing an 11% decrease from the first quarter of 2015, primarily due to the April 2015 sale of certain EOR assets.
•
First-quarter natural-gas sales volumes decreased by 50 MBOE/d, representing a 12% decrease from the first quarter of 2015, primarily due to the September 2015 sale of certain coalbed methane properties in the Rockies, the July 2015 sale of certain U.S. onshore properties and related midstream assets in East Texas, and natural production declines at Greater Natural Buttes and the Marcellus shale.
Gulf of Mexico
•
First-quarter sales volumes averaged 79 MBOE/d, representing a 12% decrease from the first quarter of 2015, primarily due to a decrease in natural-gas sales volumes due to a decline at Independence Hub (IHUB) as the last producing well went off line in December 2015. Oil sales volumes increased 26% due to the Lucius development, which achieved first oil in the first quarter of 2015; the Heidelberg development, which achieved first oil in January 2016; and contributions from the Company’s tieback program.
International
•
First-quarter sales volumes averaged 89 MBbls/d, representing a 14% decrease from the first quarter of 2015, primarily due to the timing of cargo liftings in Ghana.

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Financial
•
Anadarko’s net loss attributable to common stockholders for the first quarter of 2016 totaled $1.0 billion.
•
The Company used $137 million of cash flow from operations and ended the quarter with $2.9 billion of cash on hand.
•
In January 2016, Anadarko replaced its previous $2.0 billion 364-day senior unsecured revolving credit facility with a new $2.0 billion 364-day senior unsecured revolving credit facility (364-Day Facility) on identical terms that matures in January 2017.
•
In response to the current commodity-price environment, the Board decreased the quarterly dividend from $0.27 per share to $0.05 per share in February 2016.
•
Anadarko paid a $159.5 million Clean Water Act (CWA) penalty in the first quarter of 2016. See Note 11—Contingencies—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
•
Anadarko completed a public offering of $800 million aggregate principal amount of 4.850% Senior Notes due 2021, $1.1 billion aggregate principal amount of 5.550% Senior Notes due 2026, and $1.1 billion aggregate principal amount of 6.600% Senior Notes due 2046.
•
Western Gas Equity Partners, LP (WGP), a publicly traded consolidated subsidiary, entered into a three-year $250 million senior secured revolving credit facility maturing in March 2019, which is expandable to $500 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions.
•
The Company conveyed a limited-term nonparticipating royalty interest in certain of its coal and trona leases to a third party for $413 million, net of transaction costs.
•
In March 2016, WES issued 14 million Series A Preferred units to private investors and raised net proceeds of $440 million to partially fund its acquisition of Springfield Pipeline LLC.
•
In April 2016, WES issued an additional eight million Series A Preferred units to private investors, pursuant to the full exercise of an option granted in connection with the initial issuance, and raised net proceeds of $248 million.
•
The Company used proceeds from its $3.0 billion March 2016 Senior Notes issuances to purchase and retire $1.25 billion of its $2.0 billion 6.375% Senior Notes due September 2017 in April 2016 pursuant to a tender offer and to redeem the $1.750 billion 5.950% Senior Notes due September 2016 in May 2016.


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FINANCIAL RESULTS
 
Three Months Ended 
 March 31,
millions except per-share amounts
2016
 
2015
Oil and condensate, natural-gas, and NGLs sales
$
1,394

 
$
2,292

Gathering, processing, and marketing sales
240

 
293

Gains (losses) on divestitures and other, net
40

 
(264
)
Revenues and other
1,674

 
2,321

Costs and expenses
2,538

 
6,529

Other (income) expense
517

 
420

Income tax expense (benefit)
(383
)
 
(1,392
)
Net income (loss) attributable to common stockholders
$
(1,034
)
 
$
(3,268
)
Net income (loss) per common share attributable to common stockholders—diluted
$
(2.03
)
 
$
(6.45
)
Average number of common shares outstanding—diluted
509

 
507


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 March 31, 2016,” refer to the comparison of the three months ended March 31, 2016, to the three months ended March 31, 2015. The primary factors that affect the Company’s results of operations include commodity prices for oil, natural gas, and NGLs; sales volumes; the cost of finding such reserves; and operating costs.

Revenues and Sales Volumes
 
 
Three Months Ended March 31,
millions except percentages
 
Oil and
Condensate
 
Natural
Gas
 
NGLs
 
Total
2015 sales revenues
 
$
1,419

 
$
641

 
$
232

 
$
2,292

Changes associated with sales volumes
 
(67
)
 
(96
)
 
(23
)
 
(186
)
Changes associated with prices
 
(502
)
 
(179
)
 
(31
)
 
(712
)
2016 sales revenues
 
$
850

 
$
366

 
$
178

 
$
1,394

Increase (decrease) vs. 2015
 
(40
)%
 
(43
)%

(23
)%

(39
)%

Changes associated with sales volumes for the three months ended March 31, 2016, include decreases associated with asset divestitures.

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The following provides Anadarko’s sales volumes for the three months ended March 31:
 
 
 
2016
 
Inc (Dec) vs. 2015
 
2015
Barrels of Oil Equivalent
 
 
 
 
 
 
 
(MMBOE except percentages)
 
 
 
 
 
 
 
United States
 
 
67

 
(10
)%
 
75

International
 
 
8

 
(14
)
 
9

Total barrels of oil equivalent
 
 
75

 
(11
)
 
84

 
 
 
 
 
 
 
 
Barrels of Oil Equivalent per Day
 
 
 
 
 
 
 
(MBOE/d except percentages)
 
 
 
 
 
 
 
United States
 
 
738

 
(10
)%
 
829

International
 
 
89

 
(14
)
 
105

Total barrels of oil equivalent per day
 
 
827

 
(11
)
 
934

 _______________________________________________________________________________
MMBOE—million barrels of oil equivalent

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 the Jubilee development plan in Ghana. 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. Production of oil, natural gas, and NGLs is usually not affected by seasonal swings in demand.

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Oil and Condensate Sales Volumes, Average Prices, and Revenues
 
 
Three Months Ended 
 March 31,
 
 
2016
 
Inc (Dec) vs. 2015
 
2015
United States
 
 
 
 
 
 
Sales volumes—MMBbls
 
21

 
(1
)%
 
22

MBbls/d
 
232

 
(1
)
 
237

Price per barrel
 
$
28.04

 
(37
)
 
$
44.19

International
 
 
 
 
 
 
Sales volumes—MMBbls
 
8

 
(14
)%
 
8

MBbls/d
 
83

 
(14
)
 
98

Price per barrel
 
$
34.11

 
(37
)
 
$
54.15

Total
 
 
 
 
 
 
Sales volumes—MMBbls
 
29

 
(5
)%
 
30

MBbls/d
 
315

 
(5
)
 
335

Price per barrel
 
$
29.65

 
(37
)
 
$
47.12

Oil and condensate sales revenues (millions)
 
$
850

 
(40
)
 
$
1,419

 _______________________________________________________________________________
MMBbls—million barrels

Anadarko’s oil and condensate sales volumes decreased by 20 MBbls/d for the three months ended March 31, 2016.

•
Sales volumes in the Rockies decreased by 18 MBbls/d for the three months ended March 31, 2016, primarily due to the April 2015 sale of certain EOR assets.
•
International sales volumes decreased by 15 MBbls/d for the three months ended March 31, 2016, primarily due to the timing of cargo liftings in Ghana.
•
Sales volumes in the Gulf of Mexico increased by 12 MBbls/d for the three months ended March 31, 2016, primarily from the Lucius development, which achieved first oil in the first quarter of 2015.

Anadarko’s average oil price received decreased for the three months ended March 31, 2016, primarily due to concerns of slowing oil demand growth coupled with continued global oversupply.

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Table of Contents

Natural-Gas Sales Volumes, Average Prices, and Revenues
 
 
Three Months Ended 
 March 31,
 
 
2016
 
Inc (Dec) vs. 2015
 
2015
United States
 
 
 
 
 
 
Sales volumes—Bcf
 
210

 
(15
)%
 
246

MMcf/d
 
2,303

 
(15
)
 
2,738

Price per Mcf
 
$
1.75

 
(33
)
 
$
2.60

Natural-gas sales revenues (millions)
 
$
366

 
(43
)
 
$
641

 _______________________________________________________________________________
Bcf—billion cubic feet
MMcf/d—million cubic feet per day
Mcf—thousand cubic feet

The Company’s natural-gas sales volumes decreased by 435 MMcf/d for the three months ended March 31, 2016.

•
Sales volumes in the Rockies decreased by 174 MMcf/d for the three months ended March 31, 2016, primarily due to the September 2015 sale of certain coalbed methane properties and a natural production decline at Greater Natural Buttes, partially offset by higher sales volumes in the Wattenberg field as a result of well optimization.
•
Sales volumes in the Gulf of Mexico decreased by 136 MMcf/d for the three months ended March 31, 2016, primarily due to a decline at IHUB as the last producing well went off line in December 2015.
•
Sales volumes in the Southern and Appalachia Region decreased by 125 MMcf/d for the three months ended March 31, 2016, primarily due to the July 2015 sale of certain U.S. onshore properties and related midstream assets in East Texas and natural production declines in the Marcellus shale.

The average natural-gas price Anadarko received decreased for the three months ended March 31, 2016, primarily due to lower weather-driven residential and commercial demand as well as continued production growth in the northeast United States.


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Table of Contents

Natural-Gas Liquids Sales Volumes, Average Prices, and Revenues
 
 
Three Months Ended 
 March 31,
 
 
2016
 
Inc (Dec) vs. 2015
 
2015
United States






Sales volumes—MMBbls

11

 
(10
)%
 
12

MBbls/d

122

 
(10
)
 
136

Price per barrel

$
14.98

 
(13
)
 
$
17.29

International
 
 
 
 
 
 
Sales volumes—MMBbls
 
—

 
(14
)%
 
1

MBbls/d
 
6

 
(14
)
 
7

Price per barrel
 
$
22.78

 
(30
)
 
$
32.75

Total
 
 
 
 
 
 
Sales volumes—MMBbls
 
11

 
(10
)%
 
13

MBbls/d
 
128

 
(10
)
 
143

Price per barrel
 
$
15.32

 
(15
)
 
$
18.00

Natural-gas liquids sales revenues (millions)
 
$
178

 
(23
)
 
$
232


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 15 MBbls/d for the three months ended March 31, 2016, primarily due to increased ethane rejection in 2016 and higher sales volumes in 2015 associated with sales from storage.
Anadarko’s average NGLs price received decreased for the three months ended March 31, 2016, primarily due to decreased propane prices as a result of lower seasonal demand and a related decline in oil prices.


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Gathering, Processing, and Marketing
 
 
Three Months Ended 
 March 31,
millions except percentages
 
2016
 
Inc (Dec) vs. 2015
 
2015
Gathering, processing, and marketing sales
 
$
240

 
(18
)%
 
$
293

Gathering, processing, and marketing expense
 
215

 
(15
)
 
254

Total gathering, processing, and marketing, net
 
$
25

 
(36
)
 
$
39


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 $14 million for the three months ended March 31, 2016, primarily due to lower gathering revenues as a result of the 2015 divestiture of certain coalbed methane midstream assets, partially offset by higher marketing margins.

Gains (Losses) on Divestitures and Other, net
 
 
Three Months Ended 
 March 31,
millions except percentages
 
2016
 
Inc (Dec) vs. 2015
 
2015
Gains (losses) on divestitures
 
$
2

 
101
 %
 
$
(334
)
Other
 
38

 
(46
)
 
70

Total gains (losses) on divestitures and other, net
 
$
40

 
115

 
$
(264
)

For the three months ended March 31, 2016, gains (losses) on divestitures and other, net increased by $304 million.
•
The Company recognized a loss of $340 million during the three months ended March 31, 2015, associated with the divestiture of certain EOR assets in the Rockies, which closed in April 2015 with a sales price of $703 million, for net proceeds of $675 million after closing adjustments.
•
The Company recognized income of $54 million during the three months ended March 31, 2015, related to the settlement of a royalty lawsuit associated with a property in the Gulf of Mexico.


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Costs and Expenses
 
 
Three Months Ended 
 March 31,
 
 
2016
 
Inc (Dec) vs. 2015
 
2015
Oil and gas operating (millions)
 
$
208

 
(30
)%
 
$
296

Oil and gas operating—per BOE
 
2.77

 
(21
)
 
3.52

Oil and gas transportation (millions)
 
242

 
(21
)
 
305

Oil and gas transportation—per BOE
 
3.22

 
(11
)
 
3.63

_________________________________________________________________________
BOE—barrel of oil equivalent

Oil and gas operating expense decreased by $88 million for the three months ended March 31, 2016, due to lower nonoperated costs of $40 million primarily in Ghana due to the timing of liftings, lower expenses of $36 million as a result of divestitures in 2015, and lower workover costs of $9 million as a result of reduced activity primarily in the Rockies and the Gulf of Mexico. The related costs per BOE decreased by $0.75 for the three months ended March 31, 2016.
Oil and gas transportation expense decreased by $63 million for the three months ended March 31, 2016, due to lower sales volumes across all areas. The related costs per BOE decreased by $0.41 for the three months ended March 31, 2016, due to lower costs as a result of decreased sales volumes.
 
 
Three Months Ended 
 March 31,
millions
 
2016
 
2015
Exploration Expense
 
 
 
 
Dry hole expense
 
$
11

 
$
29

Impairments of unproved properties
 
24

 
980

Geological and geophysical expense
 
37

 
22

Exploration overhead and other
 
54

 
52

Total exploration expense
 
$
126

 
$
1,083


For the three months ended March 31, 2016, total exploration expense decreased by $957 million.
•
Dry hole expense decreased by $18 million. The Company recognized $11 million in the first quarter of 2016 primarily associated with wells in Colombia and the Gulf of Mexico, compared to $29 million in the first quarter of 2015 primarily associated with wells in Mozambique.
•
Impairments of unproved properties decreased by $956 million primarily due to a $935 million impairment in the first quarter of 2015 related to the Company’s unproved Greater Natural Buttes properties as a result of lower commodity prices.
•
Geological and geophysical expense increased by $15 million due to seismic activities in Colombia in 2016.

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Three Months Ended 
 March 31,
millions except percentages
 
2016
 
Inc (Dec) vs. 2015
 
2015
General and administrative
 
$
449

 
46
 %
 
$
307

Depreciation, depletion, and amortization
 
1,149

 
(9
)
 
1,256

Other taxes
 
117

 
(36
)
 
182

Impairments
 
16

 
(99
)
 
2,783

Other operating expense
 
16

 
(75
)
 
63


General and administrative expense for the three months ended March 31, 2016, included $203 million of expenses associated with the workforce reduction program. Excluding the workforce reduction expenses, general and administrative expense decreased by $61 million for the three months ended March 31, 2016, primarily due to lower employee-related expenses primarily associated with decreased benefit and bonus plan expenses. See Note 12—Restructuring Charges in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
Depreciation, depletion, and amortization expense decreased by $107 million for the three months ended March 31, 2016, primarily due to lower costs for U.S. onshore and midstream properties as a result of 2015 asset impairments and lower 2016 sales volumes associated with U.S. onshore properties and the 2015 divestitures of certain gathering and processing facilities.
Other taxes decreased by $65 million for the three months ended March 31, 2016, primarily due to lower ad valorem taxes of $27 million, lower U.S. severance taxes of $20 million, and lower Algerian exceptional profits taxes of $17 million. These decreases were primarily due to lower commodity prices and lower sales volumes.
Impairment expense for the three months ended March 31, 2015, included $2.3 billion related to the Company’s Greater Natural Buttes oil and gas properties and $445 million for related midstream properties in the Rockies, which were impaired due to lower forecasted commodity prices.
Other operating expense decreased by $47 million for the three months ended March 31, 2016, primarily due to expenses in 2015 for the early termination of a drilling rig.

Other (Income) Expense
 
 
Three Months Ended 
 March 31,
millions
 
2016
 
2015
Interest Expense
 
 
 
 
Debt and other
 
$
258

 
$
254

Capitalized interest
 
(38
)
 
(38
)
Total interest expense
 
$
220

 
$
216


Interest expense for the three months ended March 31, 2016, increased by $4 million, primarily due to higher debt outstanding during 2016.
 
 
Three Months Ended 
 March 31,
millions
 
2016
 
2015
(Gains) Losses on Derivatives, net
 
 
 
 
(Gains) losses on commodity derivatives, net
 
$
(28
)
 
$
(53
)
(Gains) losses on interest-rate derivatives, net
 
325

 
205

Total (gains) losses on derivatives, net
 
$
297

 
$
152


(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 as well as contract modifications. An interest-rate swap agreement was settled in March 2016, resulting in a cash payment of $193 million.
For additional information, see Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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Three Months Ended 
 March 31,
millions
 
2016
 
2015
Other (Income) Expense, net
 
 
 
 
Interest income
 
$
(3
)
 
$
(5
)
Other
 
3

 
52

Total other (income) expense, net
 
$
—

 
$
47


For the three months ended March 31, 2016, other expense, net decreased by $47 million.
•
Favorable changes in foreign currency gains/losses of $33 million were primarily associated with 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.
•
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 wells in prior years. During the first quarter of 2015, the Company recognized a charge of $22 million for the decommissioning of an additional well.

Income Tax Expense
 
 
Three Months Ended 
 March 31,
millions except percentages
 
2016
 
2015
Income tax expense (benefit)
 
$
(383
)
 
$
(1,392
)
Income (loss) before income taxes
 
(1,381
)
 
(4,628
)
Effective tax rate
 
28
%
 
30
%

The Company reported a loss before income taxes for the three months ended March 31, 2016 and 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 months ended March 31, 2016 and 2015, was primarily attributable to non-deductible Algerian exceptional profits tax for Algerian income tax purposes, the tax impact from foreign operations, and net changes in uncertain tax positions.

Net Income (Loss) Attributable to Noncontrolling Interests
 
 
Three Months Ended 
 March 31,
millions except percentages
 
2016
 
2015
Net income (loss) attributable to noncontrolling interests
 
$
36

 
$
32

Public ownership in WES, limited partnership interest
 
58.2
%
 
55.1
%
Public ownership in WGP, limited partnership interest
 
12.7
%
 
11.7
%

See Note 16—Noncontrolling Interests in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.


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LIQUIDITY AND CAPITAL RESOURCES
 
 
Three Months Ended 
 March 31,
millions
 
2016
 
2015
Net cash provided by (used in) operating activities
 
$
(137
)
 
$
(4,504
)
Net cash provided by (used in) investing activities
 
(973
)
 
(1,925
)
Net cash provided by (used in) financing activities
 
3,119

 
1,369


Overview  Anadarko believes that its cash on hand, anticipated operating cash flows, and proceeds from expected future asset monetizations will be sufficient to fund the Company’s projected 2016 operational and capital programs. In addition, the Company has available borrowing capacity to supplement its working capital needs. The Company continuously monitors its liquidity needs and evaluates available funding alternatives in light of current and expected conditions. Anadarko 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 unused credit facilities. In addition, an effective registration statement is available to Anadarko covering the sale of WGP common units owned by the Company.

Effects of Moody’s Credit Rating Downgrade  In February 2016, Standard and Poor’s affirmed Anadarko’s “BBB” long-term debt credit rating and changed the outlook from stable to negative. Later in February 2016, Moody’s Investors Service (Moody’s) lowered the Company’s long-term debt credit rating from “Baa2” to “Ba1,” which is below investment grade. In March 2016, Fitch Ratings affirmed Anadarko’s “BBB” long-term debt credit rating and changed the outlook from stable to negative.
As a result of Moody’s downgrade of Anadarko’s credit rating to a level that is below investment grade, the Company’s credit thresholds with certain derivative counterparties were reduced and in some cases eliminated, which required the Company to increase the amount of collateral posted with derivative counterparties when the Company’s net trading position is a liability in excess of the contractual threshold. No counterparties have requested termination or full settlement of derivative positions. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $1.1 billion (net of collateral) at March 31, 2016, and $1.3 billion (net of collateral) at December 31, 2015. The amount of cash posted as collateral pursuant to the contractual requirements applicable to derivative instruments with financial institutions was $420 million at March 31, 2016, and $58 million at December 31, 2015.
The Moody’s credit rating downgrade also increases the likelihood of Anadarko being required to post collateral in the form of letters of credit or cash as financial assurance of its performance under certain contractual arrangements such as pipeline transportation contracts and oil and gas sales contracts. The amount of letters of credit or cash provided as assurance of the Company’s performance under these types of contractual arrangements with respect to credit-risk-related contingent features was $200 million at March 31, 2016, and zero at December 31, 2015.
Also in February 2016, Moody’s downgraded Anadarko’s commercial paper program credit rating, which essentially eliminated the Company’s access to the commercial paper market. As a result, the Company has not issued commercial paper notes since the downgrade.

Operating Activities

One of the primary sources of variability in the Company’s cash flows from operating activities is the fluctuation in commodity prices, the impact of which Anadarko partially mitigates by entering into commodity derivatives. Sales volume changes also impact cash flow, but historically have not been as volatile as commodity prices. Anadarko’s cash flows from operating activities are also impacted by the costs related to operations and interest payments related to the Company’s outstanding debt.
Anadarko’s cash used in operating activities during the three months ended March 31, 2016, was $137 million, which included the $159.5 million payment of the CWA penalty and the payment of $79 million related to severance costs in connection with the workforce reduction program. The Company’s cash used in operating activities for the same period of 2015 was $4.5 billion, which included the $5.2 billion Tronox settlement payment. Excluding the impact of payments for the CWA penalty, severance costs, and the Tronox settlement, operating cash flows for the three months ended March 31, 2016, decreased by $610 million primarily due to decreased sales revenues primarily from lower commodity prices.

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Investing Activities

Capital Expenditures  The following presents the Company’s capital expenditures for the three months ended March 31:
millions
 
2016
 
2015
Cash Flows from Investing Activities
 
 
 
 
Additions to properties and equipment and dry hole costs
 
$
1,022

 
$
1,957

Adjustments for capital expenditures
 
 
 
 
Changes in capital accruals
 
(130
)
 
(137
)
Other
 
4

 
2

Total capital expenditures (1)
 
$
896

 
$
1,822

 ________________________________________________________________________________________
(1) 
Includes WES capital expenditures of $140 million for the three months ended March 31, 2016, and $156 million for the three months ended March 31, 2015.

The Company’s capital spending decreased by $926 million for the three months ended March 31, 2016, due to reduced development and exploration activity, which resulted in decreased development costs of $715 million primarily in the Rockies and the Southern and Appalachia Region; lower exploration costs of $128 million primarily in Colombia and Mozambique; and lower gathering, processing, and other costs of $83 million primarily due to lower expenditures for plants and gathering in the Rockies.

Carried-Interest Arrangements  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 March 31, 2016, $131 million of the $442 million carry obligation had been funded.
In the second quarter of 2013, the Company entered into a carried-interest arrangement that requires a third-party 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. At March 31, 2016, $831 million of the $860 million carry obligation had been funded.

Investments  During the three months ended March 31, 2016, the Company made capital contributions of $30 million for equity investments, which are included in other, net under Investing Activities in the Consolidated Statements of Cash Flows. These contributions were primarily associated with joint ventures for pipelines and marine well containment.

Financing Activities
millions except percentages
March 31,
2016
 
December 31,
2015
Total debt
$
18,751

 
$
15,668

Total equity
14,701

 
15,457

Debt to total capitalization ratio
56.1
%
 
50.3
%

Senior Notes  The following summarizes the Company’s debt activity related to senior notes for the three months ended March 31:
millions
2016
 
Description
Issuances
$
800

 
4.850% Senior Notes due 2021
 
1,100

 
5.550% Senior Notes due 2026
 
1,100

 
6.600% Senior Notes due 2046

The Company used proceeds from its $3.0 billion March 2016 Senior Notes issuances to purchase and retire $1.25 billion of its $2.0 billion 6.375% Senior Notes due September 2017 in April 2016 pursuant to a tender offer and to redeem the $1.750 billion 5.950% Senior Notes due September 2016 in May 2016. The Company paid $114 million in premiums for the early purchase and redemption of these senior notes.


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Revolving Credit Facilities  Anadarko has a $3.0 billion five-year senior unsecured revolving credit facility (Five-Year Facility) maturing in January 2021. In addition, in January 2016 the Company replaced its previous $2.0 billion 364-day senior unsecured revolving credit facility with a new $2.0 billion 364-day senior unsecured revolving credit facility (364-Day Facility) that matures in January 2017. The renewal included no changes to covenants or pricing, and the original bank-group fully participated.
WES has a five-year $1.2 billion senior unsecured revolving credit facility maturing in February 2019 (WES RCF), which is expandable to $1.5 billion. In March 2016, WGP entered into a three-year $250 million senior secured revolving credit facility maturing in March 2019 (WGP RCF), which is expandable to $500 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions.
The following summarizes the Company’s debt activity related to revolving credit facilities for the three months ended March 31:
millions
2016
 
Description
Borrowings
$
1,350

 
364-Day Facility
 
330

 
WES RCF
 
28

 
WGP RCF
Repayments
(1,350
)
 
364-Day Facility

Anadarko Credit Facilities  During the three months ended March 31, 2016, borrowings under the 364-Day Facility were primarily used for general corporate purposes. At March 31, 2016, the Company had no outstanding borrowings under the Five-Year Facility or the 364-Day Facility and was in compliance with all covenants therein.

WES and WGP Credit Facilities  During the three months ended March 31, 2016, WES borrowings were primarily used for general corporate purposes, including the funding of a portion of its acquisition of Springfield Pipeline LLC and capital expenditures. At March 31, 2016, WES was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $630 million at an interest rate of 1.74%, had outstanding letters of credit of $5 million, and had available borrowing capacity of $565 million.
During the three months ended March 31, 2016, WGP borrowings were used to fund the purchase of WES common units. At March 31, 2016, WGP was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $28 million at an interest rate of 2.69%, and had available borrowing capacity of $222 million.
For additional information on the revolving credit facilities, such as years of maturity, interest rates, and covenants, see Note 8—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Commercial Paper Program  The Company has a commercial paper program, which allows for a maximum of $3.0 billion of unsecured commercial paper notes and is supported by the Company’s Five-Year Facility. As a result of Moody’s downgrade of Anadarko’s commercial paper program credit rating, the Company’s access to the commercial paper market was essentially eliminated. The Company repaid $250 million of commercial paper notes during the first quarter of 2016 and at March 31, 2016, there were no outstanding borrowings under the commercial paper program. During the three months ended March 31, 2016, maximum outstanding borrowings under the commercial paper program were $906 million and the average borrowings outstanding were $435 million with a weighted-average interest rate of 1.04%. See Note 8—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information.


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Debt Maturities  Anadarko may from time to time seek to retire or purchase its outstanding debt through cash purchases and/or exchanges for other debt or equity securities in open market purchases, privately negotiated transactions, or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions, and other factors. The amounts involved may be material.
At March 31, 2016, Anadarko’s scheduled debt maturities during 2016 consisted of $1.750 billion of 5.950% Senior Notes due September 2016, which were redeemed in May 2016, and $25 million of senior amortizing notes associated with the tangible equity units (TEUs). Anadarko’s Zero-Coupon Senior Notes due 2036 (Zero Coupons) can be put to the Company in October of each year, in whole or in part, for the then-accreted value, which will be $839 million at the next put date in October 2016. The Company classified the Zero Coupons as long-term debt on the Company’s Consolidated Balance Sheet at March 31, 2016, as Anadarko has the ability and intent to refinance these obligations using long-term debt, should the put be exercised. At March 31, 2016, Anadarko’s scheduled debt maturities during 2017 consisted of $2.0 billion of 6.375% Senior Notes due September 2017 and $34 million of senior amortizing notes associated with the TEUs. In April 2016, Anadarko purchased and retired $1.25 billion of the 6.375% Senior Notes pursuant to a tender offer and $750 million of the 6.375% Senior Notes remain due in September 2017.
For additional information on the Company’s debt instruments, such as transactions during the period, years of maturity, and interest rates, see Note 8—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Tangible Equity Units  During the second quarter of 2015, Anadarko issued 9.2 million 7.50% TEUs at a stated amount of $50.00 per TEU and raised net proceeds of $445 million. Each TEU 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. During the three months ended March 31, 2016, Anadarko repaid $8 million of senior amortizing notes associated with the TEUs.

Derivative Instruments  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 derivatives 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 a level that is below investment grade. 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. The amount of cash collateral provided by the Company on its interest-rate derivatives with an other-than-insignificant financing element pursuant to the contractual requirements applicable to derivative instruments with financial institutions was $420 million at March 31, 2016, and $58 million at December 31, 2015. Additionally, an interest-rate swap agreement was settled in March 2016, resulting in a cash payment of $193 million. Anadarko expects additional net cash outlays of $65 million in 2016 related to interest-rate derivative settlements.
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 Effects of Moody’s Credit Rating Downgrade above.

Conveyance of Future Hard Minerals Royalty Revenues During the first quarter of 2016, the Company conveyed a limited-term nonparticipating royalty interest in certain of its coal and trona leases to a third party for $413 million, net of transaction costs. For additional information, see Note 10—Conveyance of Future Hard Minerals Royalty Revenues in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.


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Common Stock Dividends  Anadarko paid dividends of $25 million to its common stockholders during the three months ended March 31, 2016, and $139 million during the three months ended March 31, 2015. In response to the current commodity-price environment, the Board decreased the Company’s quarterly dividend from $0.27 per share to $0.05 per share in February 2016. 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 on a quarterly basis and is based on earnings, financial conditions, capital requirements, the effect a dividend payment would have on the Company’s compliance with relevant financial covenants, and other factors deemed relevant by the Board.

Equity Transactions  WES has a continuous offering program, which allows the issuance of up to an aggregate of $500 million of WES common units. The remaining amount of WES common units available under this program was $442 million at March 31, 2016. During the three months ended March 31, 2016, WES issued 14 million Series A Preferred units to private investors and raised net proceeds of $440 million. In April 2016, WES issued an additional eight million Series A Preferred units to private investors, pursuant to the full exercise of an option granted in connection with the initial issuance, and raised net proceeds of $248 million.

Distributions to Noncontrolling Interest Owners  WES distributed to its unitholders other than Anadarko and WGP an aggregate of $63 million during the three months ended March 31, 2016, and $54 million during the three months ended March 31, 2015. WES has made quarterly distributions to its unitholders since its initial public offering (IPO) in the second quarter of 2008, and has increased its distribution from $0.30 per common unit for the third quarter of 2008 to $0.815 per common unit for the first quarter of 2016 (to be paid in May 2016). For the three months ended March 31, 2016, the WES Series A Preferred unitholders will receive a quarterly distribution of $0.68 per unit, prorated for the 18-day period the units were outstanding during the quarter, or an aggregate $1.9 million (to be paid in May 2016).
WGP distributed to its unitholders other than Anadarko an aggregate of $11 million during the three months ended March 31, 2016, and $8 million during the three months ended March 31, 2015. WGP has made quarterly distributions to its unitholders since its IPO in December 2012, and has increased its distribution from $0.17875 per common unit for the first quarter of 2013 to $0.42375 per unit for the first quarter of 2016 (to be paid in May 2016).

RECENT ACCOUNTING DEVELOPMENTS 

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


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Table of Contents

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. The types of commodity derivative instruments used by the Company include futures, swaps, options, and fixed-price physical-delivery contracts. The volume of commodity derivatives entered into by the Company is governed by risk-management policies and may vary from year to year. Both exchange and over-the-counter traded derivative instruments may be subject to margin-deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or counterparties to satisfy these margin requirements. For additional information relating to the Company’s derivative and financial instruments, see Note 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 oil, natural gas, and NGLs. Management expects energy prices to remain unpredictable and potentially volatile. As energy prices decline or rise significantly, revenues and cash flows are likewise affected. In addition, a non-cash write-down of the Company’s oil and gas properties or goodwill may be required if commodity prices experience a significant decline. Below is a sensitivity analysis for the Company’s commodity-price-related derivative instruments.

Derivative Instruments Held for Non-Trading Purposes  The Company had derivative instruments in place to reduce the price risk associated with future production of 23 MMBbls of oil, 12 Bcf of natural gas, and 1 MMBbls of NGLs at March 31, 2016, with a net derivative asset position of $200 million. Based on actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these derivatives by $46 million, while a 10% decrease in underlying commodity prices would increase the fair value of these derivatives by $33 million. However, any cash received or paid to settle these derivatives would be substantially offset by the sales value of production covered by the derivative instruments.

Derivative Instruments Held for Trading Purposes  At March 31, 2016, the Company had a net derivative asset position of $11 million on outstanding derivative instruments entered into for trading purposes. Based on actual derivative contractual volumes, a 10% increase or decrease in underlying commodity prices would not materially impact the Company’s gains or losses on these derivative instruments.

INTEREST-RATE RISK  Borrowings, if any, under each of the 364-Day Facility, the Five-Year Facility, the commercial paper program, the WES RCF, and the WGP 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 the fair value of outstanding fixed-rate debt.
At March 31, 2016, the Company had a net derivative liability position of $1.6 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 $82 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.


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Table of Contents

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 Colombian pesos, British pounds sterling, Mozambican meticais, and Brazilian reais.
The Company also 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, which is currently under consideration by the Brazilian courts. At March 31, 2016, cash of $96 million was held in escrow.
Management periodically engages in various risk-management activities to mitigate a portion of its exposure to foreign-currency exchange-rate risk. 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 or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective as of March 31, 2016.

Changes in Internal Control over Financial Reporting

There were no changes in Anadarko’s internal control over financial reporting during the first quarter of 2016 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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Table of Contents

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 personal injury and death claims; title disputes; tax disputes; royalty claims; contract claims; contamination claims relating to oil and gas exploration, development, production, transportation, and processing; and environmental claims, including claims involving assets owned by acquired companies and claims involving assets previously sold to third parties and no longer a part of the Company’s current operations. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, tribal, and local laws and regulations. While the ultimate outcome and impact on the Company cannot be predicted with certainty, after consideration of recorded expense and liability accruals, management believes that the resolution of pending proceedings will not have a material adverse effect on the Company’s financial condition, results of operations, or cash flows.
WGR Operating, LP, a wholly owned subsidiary of the Company, is currently in negotiations with the U.S. Environmental Protection Agency and the state of Wyoming 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 11—Contingencies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q, which is incorporated herein by reference, for material developments with respect to matters previously reported in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015, 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, 2015.

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 first quarter of 2016:
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
January 1 - 31, 2016
 
4,357

 
$
36.62

 
—

 
$
—

February 1 - 29, 2016
 
64,186

 
$
38.00

 
—

 
$
—

March 1 - 31, 2016
 
611,344

 
$
44.39

 
—

 
$
—

Total
 
679,887

 
$
43.74

 
—

 
$
—

 ____________________________________________________________
(1) 
During the first quarter of 2016, 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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Table of Contents

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
 
4
(i)
 
Trustee Indenture dated as of September 19, 2006, Anadarko Petroleum Corporation to the Bank of New York Trust Company, N.A., filed as Exhibit 4.1 to Form 8-K filed on September 19, 2006
 
 
(ii)
 
Officers’ Certificate of Anadarko Petroleum Corporation dated March 17, 2016 establishing the 4.85% Senior Notes due 2021, the 5.55% Senior Notes due 2026, and the 6.60% Senior Notes due 2046, filed as Exhibit 4.1 to Form 8-K filed on March 17, 2016
 
 
(iii)
 
Form of 4.85% Senior Notes due 2021, filed as Exhibit 4.2 to Form 8-K filed on March 17, 2016
 
 
(iv)
 
Form of 5.55% Senior Notes due 2026, filed as Exhibit 4.3 to Form 8-K filed on March 17, 2016
 
 
(v)
 
Form of 6.60% Senior Notes due 2046, filed as Exhibit 4.4 to Form 8-K filed on March 17, 2016
 
10
(i)
 
First Amendment to Anadarko Petroleum Corporation 2008 Director Compensation Plan, dated February 8, 2016, filed as Exhibit 10 (xli) to Form 10-K filed on February 17, 2016
 
 
(ii)
 
364-Day Revolving Credit Agreement, dated as of January 19, 2016, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, National Association, as Syndication Agent, Bank of America, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd., Citibank, N.A., and Mizuho Bank, Ltd., as Co-Documentation Agents, and the additional lenders party thereto, filed as Exhibit 10.1 to Form 8-K filed on January 25, 2016
*
 
(iii)
 
Form of Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan Annual Deferred Shares (2016)
*
 
(iv)
 
Terms and Conditions of Elective Deferred Share Awards for Anadarko Petroleum Corporation 2008 Director Compensation Plan
*
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)
 
 
 
 
May 2, 2016
By:
/s/ ROBERT G. GWIN
 
 
Robert G. Gwin
Executive Vice President, Finance and Chief Financial Officer

52
Exhibit


EXHIBIT 10(iii)



________, 20__


Director Name
Address
Address

Dear Name:

It is my pleasure to confirm to you that on ________, you were granted _____ deferred shares of common stock of Anadarko Petroleum Corporation (“Anadarko” or the “Company”) [and non-qualified options to purchase _____ shares of Anadarko common stock (“Options”)] pursuant to the provisions of the Company’s 2008 Director Compensation Plan, as amended (the “Plan”). A copy of the Plan Summary is attached for your reference.

[Separation from Service Option: Pursuant to your distribution election, your deferred shares will become payable to you in [a lump-sum] [2 to 15 annual installments] upon your separation of service from the Company. The deferred shares are subject to a one-year minimum holding period. Accordingly, in the event your separation from service occurs prior to the one-year anniversary of the date of grant of your deferred shares, your [deferred shares will be settled in a lump-sum within 30 days following the one-year anniversary of the grant date] [installments will commence within 30 days following the one-year anniversary of the grant date rather than your separation from service].]

[Specified Month & Year Option: Pursuant to your distribution election, your deferred shares will become payable to you in [a lump-sum] [2 to 15 annual installments] in the month and year specified by you. The earliest date that a specific month and year distribution can be made is the one-year anniversary of the grant of the deferred shares.]

[Earlier of Separation from Service or Specified Month & Year Option: Pursuant to your distribution election, your deferred shares will become payable to you in [a lump-sum] [2 to 15 annual installments] in the month and year specified by you. The earliest date that a specific month and year distribution can be made is the one-year anniversary of the grant of the deferred shares. However, if you have a separation from service prior to the specified month and year, your distribution will commence within 30 days following your separation from service in the method of payment you elected. The deferred shares are subject to a one-year minimum holding period. Accordingly, in the event your separation from service occurs prior to the one-year anniversary of the date of grant of your deferred shares, your [deferred shares will be settled in a lump-sum within 30 days following the one-year anniversary of the grant date] [installments will commence within 30 days following the one-year anniversary of the grant date rather than your separation from service].]

In the event of your death or Permanent Disability (as defined in the Plan), any deferred shares will be distributed to you or, in the event of your death, your designated beneficiary(ies) within 30 days following the date of your death or Permanent Disability.




EXHIBIT 10(iii)


In the event of a Change of Control (as defined in the Plan), your deferred shares will be distributed in accordance with Section 14 of the Plan.

Upon grant, the deferred shares will not be issued in your name, but will be held by the Company, either in book-entry form or by the Company’s Benefits Trust (the “Trust”), until they become transferable to you in accordance with this letter and your election form. You should note that the deferred shares held in the Trust are considered an unsecured obligation of the Company and any and all assets held in the Trust are subject to claims of the general creditors of the Company. Until the issuance of common stock in settlement of your deferred shares, you will not have rights as a stockholder of the Company. Although you will not have beneficial ownership of the deferred shares until they are actually transferred to you, you will have the opportunity to direct the voting of your deferred shares (which voting instructions the Trustee of the Trust may not follow, in its sole discretion) and such deferred shares will be counted toward your stock ownership requirements. You will also receive a cash payment with respect to each deferred share equal to the cash dividends that are paid on a share of the Company’s common stock each quarter, with such cash amount to be paid within 30 days after the date that such dividends are paid to the Company’s regular stockholders. Your deferred shares are subject to the terms of the Plan (including the restrictions on transfer, assignment and pledge), your election form and this letter.

[Your Options will vest at the rate of ________ and have an exercise price equal to the closing stock price on ________ of $____. Any unexercised Options shall expire 10 years from the date of grant, or on ________. Your Options are subject to the terms of the Plan and this letter.]

[Upon vesting, the Options may be exercised in whole or in part by filing a written notice with the Company’s Corporate Secretary at its corporate headquarters. Such notice shall be in the form specified by the Company. Payments of all amounts due (e.g., exercise price and applicable withholding taxes) may be made either (i) in cash; (ii) in the Company’s common stock (by either actual delivery of common stock or by attestation presenting satisfactory proof of beneficial ownership of such common stock) already owned; or (iii) any combination of cash and common stock. The fair market value of such common stock as delivered shall be valued as of the closing sales price at which common stock is sold on the date of exercise, as reported in the NYSE-Composite Transactions by The Wall Street Journal. No shares shall be issued or delivered until full payment of the exercise price and applicable withholding taxes, if any, has been made.]

[Unexercised Options shall expire and be forfeited (without value) in the event you cease to be a director of the Company, unless otherwise provided below (provided that in no event may the Options be exercised more than 10 years from the date of grant):

(i) Retirement. If you cease to be a director of the Company by reason of Retirement (as defined below), any and all unvested Options will vest and become fully exercisable on the date of your cessation from the Company’s Board of Directors and you (or, in the event of your death, your legal representative) may, within a period of not more than twenty-­four (24) months after the date of such cessation, exercise the Options. "Retirement" for purposes hereof is defined as (i) 10 years of service as a director of the




EXHIBIT 10(iii)


Company (ii) attainment of age 55 and five years of service as a director of the Company, or (iii) attainment of age 65.

(ii) Death. If you cease to be a director of the Company by reason of death, any outstanding Options shall vest and be immediately exercisable with respect to all or any part of the Options which remain unexercised. Your legal representative or other person or persons to whom your rights under the Options shall pass to by will or the laws of descent and distribution, may, within a period of not more than twelve (12) months after the date of death, exercise the Options. In the event of your death after your cessation as a director, your legal representative will have the remaining exercise period awarded to you by your reason of cessation as provided in this letter or the Plan.

(iii) Permanent Disability. If you cease to be a director of the Company by reason of Permanent Disability (as defined in the Plan), any outstanding Options shall vest and be immediately exercisable with respect to all or any part of the Options which remain unexercised. You (or, in the event of your death, your legal representative) may, within a period of not more than twenty-four (24) months after the date of such cessation as a director, exercise the Options.

(iv) Resignation from the Board of Directors. If you resign from the Company’s Board of Directors (other than by reason of Retirement), all unvested Options shall be forfeited and you (or, in the event of your death, your legal representative) may, within a period of not more than three (3) months after the effective date of such resignation, exercise vested Options.]

[The Options are not transferable except by will or the laws of descent and distribution. Options are exercisable, during your lifetime, only by you. Upon any attempt to transfer, assign, pledge, hypothecate or otherwise dispose of the Options, or of any right or privilege conferred hereby, contrary to the provisions hereof, or upon the levy of any attachment or similar process upon the Options or any right or privilege conferred hereby, the Options and the right and privilege conferred hereby shall immediately become null and void.]

[You shall have no rights as a stockholder with respect to any shares of common stock subject to the Options prior to the date you are issued a certificate or certificates for such shares, or until such shares are recorded on the books of the Company’s stock transfer agent.]

You are solely responsible for the payment of any taxes associated with the issuance or settlement of deferred shares [or the grant, vesting or exercise of Options]. You acknowledge that the Company has made no representation as to the tax consequences of your deferred shares [or Options] hereunder.

[Unless otherwise directed by the Company’s Board of Directors or a committee thereof made up of two or more “non-employee directors” (within the meaning of Rule 16b-3 of the Securities Exchange Act of 1934, as amended), the Company will withhold from your award of deferred shares the number of shares of common stock necessary to satisfy the Company’s (or any affiliate’s) statutory obligation under the laws of Canada (and its provincial or local




EXHIBIT 10(iii)


governments) to withhold taxes and other amounts determined based on the greatest withholding rates, but in no event less than the minimum, under such laws, including payroll taxes, if applicable, that may be utilized without creating adverse accounting treatment with respect to such award, with the number of shares of common stock so withheld to be determined in a manner consistent with the Company’s accounting practices and based on the fair market value of a share of common stock on the date that the value of the award is included in your gross income under such laws.]

Please note that this letter serves as your Award Agreement and is for your personal files. You are not required to sign and return any documents.

For your personal records, we have enclosed a summary of all your stock options and deferred shares granted as of ________.

If you have any questions or concerns, please contact ________ at ________ or ________.

Sincerely,



Exhibit


EXHIBIT 10(iv)



Terms and Conditions of Elective Deferred Share Awards
Anadarko Petroleum Corporation 2008 Director Compensation Plan


•
Grant of Deferred Shares: On the last business day of each quarter during 20__, you will be granted a number of Deferred Shares with a grant date fair value equal to the amount of your quarterly fees you elected to defer for such quarter in the form of Deferred Shares in accordance with your Form of Compensation Election (your “Election Form”). You will be provided a quarterly summary of the number of Deferred Shares issued hereunder, which shall be subject to the terms and conditions set forth herein.

•
Deferred Shares Generally: Deferred Shares represent a vested contractual right to receive shares of Anadarko Petroleum Corporation (the “Company”) common stock, par value $0.10 per share (“Common Stock”), at the time(s) of settlement specified in your Election Form. Upon grant, the Deferred Shares will not be issued in your name, but will be held by the Company, either in book-entry form or by the Company’s Benefits Trust (the “Trust”) until the time of settlement set forth in your Election Form. Deferred Shares are considered an unsecured obligation of the Company and any and all assets held in the Trust are subject to claims of the general creditors of the Company. Until the issuance of Common Stock in settlement of your Deferred Shares, you will not have rights as a stockholder of the Company.

•
Voting Rights: Although you will not have beneficial ownership of the Deferred Shares prior to settlement, to the extent the shares underlying your Deferred Shares are held by the Trust, you may have the opportunity to direct the voting of your Deferred Shares (which voting instructions the Trustee of the Trust may not follow, in its sole discretion) and such Deferred Shares will be counted toward your stock ownership requirements.

•
Dividend Equivalents: You will receive a cash payment equal to the cash dividends that are paid on the Company’s common stock each quarter, with such cash amount to be paid within 30 days after the date that such dividends are paid to the Company’s regular stockholders.

•
Mandatory Holding Period: Except in the event of your death or Permanent Disability or a Change of Control, no shares of Common Stock will be issued in settlement of your Deferred Shares prior to the one-year anniversary of the grant of the applicable Deferred Shares.

•
Subject to Terms of Plan: Your Deferred Shares are subject to the terms and conditions of the Company’s 2008 Director Compensation Plan and the Election Form. In the event of any conflict between the 2008 Director Compensation Plan and the Election Form, the 2008 Director Compensation Plan shall control.

•
Payment of Taxes: You are solely responsible for the payment of any taxes associated with the issuance or settlement of Deferred Shares. You acknowledge that the Company has made no representation as to the tax consequences of your Deferred Shares hereunder.





Exhibit


EXHIBIT 31(i)
CERTIFICATIONS
I, R. A. Walker, certify that:
1.
I have reviewed this quarterly report on Form 10-Q of Anadarko Petroleum Corporation;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

May 2, 2016
 
/s/ R. A. WALKER
R. A. Walker
Chairman, President and Chief Executive Officer



Exhibit


EXHIBIT 31(ii)
CERTIFICATIONS
I, Robert G. Gwin, certify that:
1.
I have reviewed this quarterly report on Form 10-Q of Anadarko Petroleum Corporation;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

May 2, 2016

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


Exhibit


EXHIBIT 32
SECTION 1350 CERTIFICATION OF PERIODIC REPORT
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, R. A. Walker, Chairman, President and Chief Executive Officer of Anadarko Petroleum Corporation (Company), and Robert G. Gwin, Executive Vice President, Finance and Chief Financial Officer of the Company, certify to the best of our knowledge that:
(1)
the Quarterly Report on Form 10-Q of the Company for the period ended March 31, 2016, as filed with the Securities and Exchange Commission on the date hereof (Report), fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
May 2, 2016
  
 
 
 
 
 
  
/s/ R. A. WALKER
 
  
R. A. Walker
 
  
Chairman, President and Chief Executive Officer
 
 
 
May 2, 2016
  
 
 
 
 
 
  
/s/ ROBERT G. GWIN
 
  
Robert G. Gwin
 
  
Executive Vice President, Finance and Chief Financial Officer
This certification is made solely pursuant to 18 U.S.C. Section 1350, and not for any other purpose. A signed original of this written statement required by Section 906 will be retained by Anadarko and furnished to the Securities and Exchange Commission or its staff upon request.


apc-20160331.xml
Attachment: XBRL INSTANCE DOCUMENT

apc-20160331.xsd
Attachment: XBRL TAXONOMY EXTENSION SCHEMA DOCUMENT

apc-20160331_cal.xml
Attachment: XBRL TAXONOMY EXTENSION CALCULATION LINKBASE DOCUMENT

apc-20160331_def.xml
Attachment: XBRL TAXONOMY EXTENSION DEFINITION LINKBASE DOCUMENT

apc-20160331_lab.xml
Attachment: XBRL TAXONOMY EXTENSION LABEL LINKBASE DOCUMENT

apc-20160331_pre.xml
Attachment: XBRL TAXONOMY EXTENSION PRESENTATION LINKBASE DOCUMENT

apc20161q10q.pdf
Attachment: ANADARKO PETROLEUM CORPORATION 1ST QTR 2016 FORM 10-Q - PDF

v3.4.0.3
Document and Entity Information - shares
 3 Months Ended
Mar. 31, 2016
Apr. 19, 2016
Document And Entity Information [Abstract]    
Trading Symbol APC  
Entity Registrant Name ANADARKO PETROLEUM CORP  
Entity Central Index Key 0000773910  
Document Type 10-Q  
Document Period End Date Mar. 31, 2016  
Amendment Flag false  
Document Fiscal Year Focus 2016  
Document Fiscal Period Focus Q1  
Current Fiscal Year End Date --12-31  
Entity Filer Category Large Accelerated Filer  
Entity Common Stock, Shares Outstanding   510,426,628
v3.4.0.3
CONSOLIDATED STATEMENTS OF INCOME - USD ($)
shares in Millions, $ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Revenues and Other    
Oil and condensate sales $ 850 $ 1,419
Natural-gas sales 366 641
Natural-gas liquids sales 178 232
Gathering, processing, and marketing sales 240 293
Gains (losses) on divestitures and other, net 40 (264)
Total 1,674 2,321
Costs and Expenses    
Oil and gas operating 208 296
Oil and gas transportation 242 305
Exploration 126 1,083
Gathering, processing, and marketing 215 254
General and administrative 449 307
Depreciation, depletion, and amortization 1,149 1,256
Other taxes 117 182
Impairments 16 2,783
Other operating expense 16 63
Total 2,538 6,529
Operating Income (Loss) (864) (4,208)
Other (Income) Expense    
Interest expense 220 216
(Gains) losses on derivatives, net 299 152
Other (income) expense, net 0 47
Total 517 420
Income (Loss) Before Income Taxes (1,381) (4,628)
Income tax expense (benefit) (383) (1,392)
Net Income (Loss) (998) (3,236)
Net income (loss) attributable to noncontrolling interests 36 32
Net Income (Loss) Attributable to Common Stockholders $ (1,034) $ (3,268)
Per Common Share    
Net income (loss) attributable to common stockholders—basic $ (2.03) $ (6.45)
Net income (loss) attributable to common stockholders—diluted $ (2.03) $ (6.45)
Average Number of Common Shares Outstanding—Basic 509 507
Average Number of Common Shares Outstanding—Diluted 509 507
Dividends (per common share) $ 0.05 $ 0.27
Commodity Contract and Interest Rate Swap [Member]    
Other (Income) Expense    
(Gains) losses on derivatives, net $ 297 $ 152
Tronox Litigation [Member] | Judicial Ruling [Member]    
Other (Income) Expense    
Tronox-related contingent loss $ 0 $ 5
v3.4.0.3
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Statement of Comprehensive Income [Abstract]    
Net Income (Loss) $ (998) $ (3,236)
Adjustments for derivative instruments    
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net 3 2
Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net (1) (1)
Total adjustments for derivative instruments, net of taxes 2 1
Adjustments for pension and other postretirement plans    
Net gain (loss) incurred during period (166) 0
Income taxes on net gain (loss) incurred during period 61 0
Prior service credit (cost) incurred during period (1) 0
Income taxes on prior service credit (cost) incurred during period 1 0
Amortization of net actuarial (gain) loss to general and administrative expense 8 13
Income taxes on amortization of net actuarial (gain) loss to general and administrative expense (3) (4)
Amortization of net prior service (credit) cost to general and administrative expense (15) 0
Income taxes on amortization of net prior service (credit) cost to general and administrative expense 5 0
Total adjustments for pension and other postretirement plans, net of taxes (110) 9
Total (108) 10
Comprehensive Income (Loss) (1,106) (3,226)
Comprehensive income (loss) attributable to noncontrolling interests 36 32
Comprehensive Income (Loss) Attributable to Common Stockholders $ (1,142) $ (3,258)
v3.4.0.3
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Millions
Mar. 31, 2016
Dec. 31, 2015
Current Assets    
Cash and cash equivalents ($111 and $100 related to VIEs) $ 2,947 $ 939
Accounts receivable (net of allowance of $12 and $11)    
Customers ($47 and $81 related to VIEs) 633 652
Others ($81 and $84 related to VIEs) 1,759 1,817
Other current assets 428 573
Total 5,767 3,981
Properties and Equipment    
Cost 71,541 70,683
Less accumulated depreciation, depletion, and amortization 38,015 36,932
Net properties and equipment ($4,940 and $4,859 related to VIEs) 33,526 33,751
Other Assets ($624 and $644 related to VIEs) 2,304 2,268
Goodwill and Other Intangible Assets ($1,244 and $1,220 related to VIEs) 6,325 6,331
Total Assets 47,922 46,331
Current Liabilities    
Accounts payable ($183 and $179 related to VIEs) 2,505 2,850
Current asset retirement obligations 297 309
Interest payable 158 247
Other taxes payable ($28 and $18 related to VIEs) 339 318
Accrued expenses 333 424
Short-term debt 3,025 32
Total 6,657 4,180
Long-term Debt 15,726 15,636
Other Long-term Liabilities    
Deferred income taxes 4,940 5,400
Asset retirement obligations ($131 and $127 related to VIEs) 1,760 1,750
Other 4,138 3,908
Total 10,838 11,058
Stockholders' equity    
Common stock, par value $0.10 per share (1.0 billion shares authorized, 531.1 million and 528.3 million shares issued) 53 52
Paid-in capital 9,328 9,265
Retained earnings 3,821 4,880
Treasury stock (20.7 million and 20.0 million shares) (1,025) (995)
Accumulated other comprehensive income (loss) (491) (383)
Total Stockholders’ Equity 11,686 12,819
Noncontrolling interests 3,015 2,638
Total Equity 14,701 15,457
Total Liabilities and Equity $ 47,922 $ 46,331
v3.4.0.3
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
$ in Millions
Mar. 31, 2016
Dec. 31, 2015
Cash and cash equivalents ($111 and $100 related to VIEs) $ 2,947 $ 939
Allowance for uncollectible accounts 12 11
Customers ($47 and $81 related to VIEs) 633 652
Others ($81 and $84 related to VIEs) 1,759 1,817
Net properties and equipment ($4,940 and $4,859 related to VIEs) 33,526 33,751
Other Assets ($624 and $644 related to VIEs) 2,304 2,268
Goodwill and Other Intangible Assets ($1,244 and $1,220 related to VIEs) 6,325 6,331
Accounts payable ($183 and $179 related to VIEs) 2,505 2,850
Other taxes payable ($28 and $18 related to VIEs) 339 318
Asset retirement obligations ($131 and $127 related to VIEs) $ 1,760 $ 1,750
Common stock, par value per share $ 0.1 $ 0.1
Common stock, shares authorized 1,000,000,000 1,000,000,000
Common stock, shares issued 531,100,000 528,300,000
Treasury stock, shares 20,700,000 20,000,000
Variable Interest Entity, Primary Beneficiary [Member]    
Cash and cash equivalents ($111 and $100 related to VIEs) $ 111 $ 100
Customers ($47 and $81 related to VIEs) 47 81
Others ($81 and $84 related to VIEs) 81 84
Net properties and equipment ($4,940 and $4,859 related to VIEs) 4,940 4,859
Other Assets ($624 and $644 related to VIEs) 624 644
Goodwill and Other Intangible Assets ($1,244 and $1,220 related to VIEs) 1,244 1,220
Accounts payable ($183 and $179 related to VIEs) 183 179
Other taxes payable ($28 and $18 related to VIEs) 28 18
Asset retirement obligations ($131 and $127 related to VIEs) $ 131 $ 127
v3.4.0.3
CONSOLIDATED STATEMENT OF EQUITY - 3 months ended Mar. 31, 2016 - USD ($)
$ in Millions
Total
Subsidiary Equity Transactions [Member]
Common Stock [Member]
Paid-in Capital [Member]
Paid-in Capital [Member]
Subsidiary Equity Transactions [Member]
Retained Earnings [Member]
Treasury Stock [Member]
Accumulated Other Comprehensive Income (Loss) [Member]
Noncontrolling Interests [Member]
Noncontrolling Interests [Member]
Subsidiary Equity Transactions [Member]
Balance at Dec. 31, 2015 $ 15,457   $ 52 $ 9,265   $ 4,880 $ (995) $ (383) $ 2,638  
Net income (loss) (998)         (1,034)     36  
Common stock issued 63   1 62            
Dividends—common stock (25)         (25)        
Repurchase of common stock (30)           (30)      
Subsidiary equity transactions   $ 420     $ 1         $ 419
Distributions to noncontrolling interest owners (78)               (78)  
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net 2             2    
Adjustments for pension and other postretirement plans (110)             (110)    
Balance at Mar. 31, 2016 $ 14,701   $ 53 $ 9,328   $ 3,821 $ (1,025) $ (491) $ 3,015  
v3.4.0.3
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Cash Flows from Operating Activities    
Net income (loss) $ (998) $ (3,236)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities    
Depreciation, depletion, and amortization 1,149 1,256
Dry hole expense and impairments of unproved properties 35 1,009
Impairments 16 2,783
(Gains) losses on divestitures, net (2) 334
Total (gains) losses on derivatives, net 299 152
Operating portion of net cash received (paid) in settlement of derivative instruments 105 91
Other 115 45
Changes in assets and liabilities    
(Increase) decrease in accounts receivable 46 357
Increase (decrease) in accounts payable and accrued expenses (403) (279)
Other items, net (86) (608)
Net cash provided by (used in) operating activities (137) (4,504)
Cash Flows from Investing Activities    
Additions to properties and equipment and dry hole costs (1,022) (1,957)
Divestitures of properties and equipment and other assets 35 22
Other, net 14 10
Net cash provided by (used in) investing activities (973) (1,925)
Cash Flows from Financing Activities    
Borrowings, net of issuance costs 4,682 4,583
Repayments of debt (1,608) (2,830)
Financing portion of net cash received (paid) for derivative instruments (555) (146)
Increase (decrease) in outstanding checks (150) (39)
Dividends paid (25) (139)
Repurchase of common stock (30) (36)
Issuance of common stock, including tax benefit on share-based compensation awards 30 12
Distributions to noncontrolling interest owners (78) (67)
Proceeds from conveyance of future hard minerals royalty revenues, net of transaction costs 413 0
Net cash provided by (used in) financing activities 3,119 1,369
Effect of Exchange Rate Changes on Cash (1) (1)
Net Increase (Decrease) in Cash and Cash Equivalents 2,008 (5,061)
Cash and Cash Equivalents at Beginning of Period 939 7,369
Cash and Cash Equivalents at End of Period 2,947 2,308
Subsidiary Equity Transactions [Member]    
Cash Flows from Financing Activities    
Sale of subsidiary units 440 31
Tronox Litigation [Member] | Judicial Ruling [Member]    
Changes in assets and liabilities    
Tronox-related contingent liability 0 (5,210)
Excluding Certain International Locations [Member]    
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities    
Deferred income taxes $ (413) $ (1,198)
v3.4.0.3
Summary of Significant Accounting Policies
 3 Months Ended
Mar. 31, 2016
Accounting Policies [Abstract]  
Summary of Significant Accounting Policies
1. Summary of Significant Accounting Policies

General  Anadarko Petroleum Corporation is engaged in the exploration, development, production, and marketing of oil, condensate, natural gas, and natural gas liquids (NGLs), and in the marketing of anticipated production of liquefied natural gas (LNG). In addition, the Company engages in the gathering, processing, treating, and transporting of oil, condensate, natural gas, 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 Consolidated Financial Statements have been prepared in conformity with generally accepted accounting principles in the United States (GAAP). The Consolidated Financial Statements include the accounts of Anadarko and subsidiaries in which Anadarko holds, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs) for which Anadarko is the primary beneficiary. All intercompany transactions have been eliminated. Undivided interests in oil and natural-gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities over which Anadarko has the ability to exercise significant influence over operating and financial policies and VIEs for which Anadarko is not the primary beneficiary are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost, and subsequently adjusted for the Company’s proportionate share of earnings, losses, and distributions. Other investments are carried at original cost. Investments accounted for using the equity method and cost method are reported as a component of other assets. Certain prior-period amounts have been reclassified to conform to the current-year presentation.

Use of Estimates  The preparation of financial statements in accordance with GAAP 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 require capitalized debt issuance 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. The Company adopted these ASUs on January 1, 2016, using a retrospective approach. The adoption resulted in a reclassification that reduced other current assets and short-term debt by $1 million and reduced other assets and long-term debt by $82 million on the Company’s Consolidated Balance Sheet at December 31, 2015.
The FASB issued ASU 2015-02, Consolidation (Topic 810)—Amendments to the Consolidation Analysis. The Company adopted this ASU on January 1, 2016. In accordance with the new ASU, Western Gas Equity Partners, LP (WGP) and Western Gas Partners, LP (WES), publicly traded consolidated subsidiaries of the Company, are considered VIEs for which the Company is the primary beneficiary. Prior to adoption of the ASU, WGP and WES were consolidated by the Company under the voting interest model and, after adoption, the Company will continue to consolidate WGP and WES under the variable interest model. While this ASU requires additional financial statement disclosure, it has no impact on the Company’s consolidated results of operations, cash flows, or financial position. See Note 17—Variable Interest Entities.
1. Summary of Significant Accounting Policies (Continued)

The FASB issued ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. This ASU will simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This ASU is effective for annual and interim periods beginning in 2017 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 2016-02, Leases (Topic 842). This ASU requires the lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet and disclose key information about their leasing transactions. This ASU is effective for annual and interim periods beginning in 2019. The Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements.
The FASB issued ASU 2016-01, Financial Instruments—Overall: Recognition and Measurement of Financial Assets and Financial Liabilities (Subtopic 825-10). This ASU amends existing requirements on the classification and measurement of financial instruments. Changes to the current requirements primarily affect the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. This ASU is effective for annual periods beginning in 2018 with early adoption of certain provisions 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 (Topic 606), ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), and ASU 2016-10, Revenues from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, which supersede 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 require an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Company is required to adopt the new standards in the first quarter of 2018 using one of two retrospective application methods. The Company is continuing to evaluate the provisions of these ASUs, and has not determined the impact these standards may have on its consolidated financial statements and related disclosures or decided upon the method of adoption.
v3.4.0.3
Inventories
 3 Months Ended
Mar. 31, 2016
Energy Related Inventory [Abstract]  
Inventories
2. Inventories

The following summarizes the major classes of inventories included in other current assets:
millions
March 31,
2016
 
December 31,
2015
Oil
$
96

 
$
116

Natural gas
25

 
36

NGLs
67

 
64

Total inventories
$
188

 
$
216
v3.4.0.3
Assets Held for Sale
 3 Months Ended
Mar. 31, 2016
Property, Plant and Equipment [Abstract]  
Assets Held for Sale
3. Assets Held for Sale

Certain U.S. onshore assets in East Texas/Louisiana included in the oil and gas exploration and production reporting segment satisfied criteria to be considered held for sale during the first quarter of 2016. The sale of these assets closed in April 2016 for a sales price of $107 million, subject to closing adjustments. At March 31, 2016, the balances of assets and liabilities associated with assets held for sale were not material.
v3.4.0.3
Impairments
 3 Months Ended
Mar. 31, 2016
Asset Impairment Charges [Abstract]  
Impairments
4. Impairments

Impairments of long-lived assets are included in impairment expense in the Company’s Consolidated Statements of Income. The following summarizes impairments of long-lived assets and the related post-impairment fair values by segment:
  
Three Months Ended
millions
Impairment
 
Fair Value (1)
March 31, 2016
 
 
 
Oil and gas exploration and production
 
 
 
Long-lived assets held for use
 
 
 
U.S. onshore properties
$
4

 
$
585

Gulf of Mexico properties
1

 
—

Cost-method investment (2)
1

 
32

Midstream
 
 
 
Long-lived assets held for use
10

 
3

Total
$
16

 
$
620

 
 
 
 
March 31, 2015
 
 
 
Oil and gas exploration and production
 
 
 
Long-lived assets held for use
 
 
 
U.S. onshore properties
$
2,307

 
$
1,299

Midstream
 
 
 
Long-lived assets held for use
476

 
206

Total
$
2,783

 
$
1,505


__________________________________________________________________
(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 first quarter of 2015 were primarily related to the Company’s Greater Natural Buttes oil and gas and midstream properties in the Rockies, which were impaired due to lower forecasted commodity prices.
In addition to the long-lived asset impairments above, the Company recognized a $935 million impairment of unproved Greater Natural Buttes properties during the first quarter of 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.

Potential for Future Impairments  During 2015, the Company recognized significant impairments of proved oil and gas and midstream properties and impairments of unproved oil and gas properties, primarily as a result of lower forecasted commodity prices and related changes to the Company’s drilling plans. While commodity prices continued to decline during the first quarter of 2016, the Company did not recognize any material impairments. At March 31, 2016, the Company’s estimate of undiscounted future cash flows attributable to a certain depletion group with a net book value of approximately $2.1 billion indicated that the carrying amount was expected to be recovered; however, this depletion group may be at risk for impairment if the estimates of future cash flows decline. The Company estimates that, if this depletion group becomes impaired in a future period, the Company could recognize non-cash impairments in that period in excess of $1.0 billion. It is also reasonably possible that prolonged low or further declines in commodity prices, changes to the Company’s drilling plans in response to lower prices, or increases in drilling or operating costs could result in additional impairments.
v3.4.0.3
Suspended Exploratory Well Costs
 3 Months Ended
Mar. 31, 2016
Capitalized Exploratory Well Costs [Abstract]  
Suspended Exploratory Well Costs
5. Suspended Exploratory Well Costs

The Company’s suspended exploratory well costs were $1.1 billion at March 31, 2016, and December 31, 2015. During the three months ended March 31, 2016, suspended exploratory well costs previously capitalized for a period greater than one year since the completion of drilling at December 31, 2015, charged to exploration expense were not material. 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.
v3.4.0.3
Derivative Instruments
 3 Months Ended
Mar. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivative Instruments
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 Cushing, Oklahoma or Sullom Voe, Scotland for oil and Henry Hub, Louisiana for natural gas. Basis swaps are periodically used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and a ceiling price (collar) for expected future oil and natural-gas sales. Derivative instruments are also used to manage commodity-price risk inherent in customer price requirements and to fix margins on the future sale of natural gas and NGLs from the Company’s leased storage facilities (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 15—Accumulated Other Comprehensive Income (Loss).

6. Derivative Instruments (Continued)

Oil and Natural-Gas Production/Processing Derivative Activities  The oil prices listed below are a combination of New York Mercantile Exchange (NYMEX) West Texas Intermediate and Intercontinental Exchange, Inc. (ICE) Brent Blend prices. The natural-gas prices listed below are NYMEX Henry Hub prices. The NGLs prices listed below are Oil Price Information Services prices. The following is a summary of the Company’s derivative instruments related to oil and natural-gas production/processing derivative activities at March 31, 2016:
 
2016 Settlement
Oil
 
Three-Way Collars (MBbls/d)
83

Average price per barrel
 
Ceiling sold price (call)
$
63.82

Floor purchased price (put)
$
54.46

Floor sold price (put)
$
42.77

Natural Gas
 
Fixed-Price Contracts (thousand MMBtu/d)
43

Average price per MMBtu
$
2.24

NGLs
 
Fixed-Price Contracts (MBbls/d)
4

Average price per barrel
$
12.93

__________________________________________________________________
MBbls/d—thousand barrels per day
MMBtu/d—million British thermal units per day
MMBtu—million British thermal units

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

Marketing and Trading Derivative Activities  The Company had financial derivative transactions with notional volumes of natural gas totaling 4 billion cubic feet (Bcf) at March 31, 2016, and 8 Bcf at December 31, 2015, that were entered into to mitigate commodity-price risk related to fixed-price purchase and sales contracts and storage activity.

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). The Company used proceeds from its $3.0 billion March 2016 Senior Notes issuances to purchase and retire $1.25 billion of its $2.0 billion 6.375% Senior Notes due September 2017 in April 2016 pursuant to a tender offer and to redeem the $1.750 billion 5.950% Senior Notes due September 2016 in May 2016. The outstanding interest-rate swaps with a notional amount of $1.7 billion due prior to or at September 2021 will manage interest-rate risk associated with the potential refinancing of the Company’s $900 million Senior Notes due 2019 and the Zero-Coupon Senior Notes due 2036 (Zero Coupons), should the Zero Coupons be put to the Company prior to the swap termination dates. At the next put date in October 2016, the accreted value of the Zero Coupons will be $839 million. See Note 8—Debt and Interest Expense. Depending on market conditions, liability-management actions, or other factors, the Company may enter into offsetting interest-rate swap positions, or settle or amend, certain or all of the currently outstanding interest-rate swaps. 
In February 2016, in exchange for amended terms with certain counterparties, the Company modified the mandatory termination dates from 2021 to 2018 and, in some cases, the related fixed interest rates on interest-rate swaps with an aggregate notional principal amount of $500 million. Additionally, an interest-rate swap agreement was settled in March 2016, resulting in a cash payment of $193 million.
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 March 31, 2016: 
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%
$
500

 
 
September 2016 – 2046
 
September 2018
 
6.559%
$
300

 
 
September 2016 – 2046
 
September 2020
 
6.509%
$
450

 
 
September 2017 – 2047
 
September 2018
 
6.445%
$
100

 
 
September 2017 – 2047
 
September 2020
 
6.891%
$
250

 
 
September 2017 – 2047
 
September 2021
 
6.570%

6. Derivative Instruments (Continued)

Effect of Derivative Instruments—Balance Sheet  The following summarizes the fair value of the Company’s derivative instruments:
 
 
Gross Derivative Assets
 
Gross Derivative Liabilities
millions
 
March 31,
 
December 31,
 
March 31,
 
December 31,
Balance Sheet Classification
 
2016
 
2015
 
2016
 
2015
Commodity derivatives
 
 
 
 
 
 
 
 
Other current assets
 
$
322

 
$
462

 
$
(116
)
 
$
(177
)
Other assets
 
7

 
8

 
—

 
—

Accrued expenses
 
—

 
—

 
(2
)
 
(3
)
 
 
329

 
470

 
(118
)
 
(180
)
Interest-rate derivatives
 
 
 
 
 
 
 
 
Other current assets
 
2

 
2

 
—

 
—

Other assets
 
20

 
54

 
—

 
—

Accrued expenses
 
—

 
—

 
(90
)
 
(54
)
Other liabilities
 
—

 
—

 
(1,550
)
 
(1,488
)
 
 
22

 
56

 
(1,640
)
 
(1,542
)
Total derivatives
 
$
351

 
$
526

 
$
(1,758
)
 
$
(1,722
)


Effect of Derivative Instruments—Statement of Income  The following summarizes gains and losses related to derivative instruments:
millions
 
Three Months Ended 
 March 31,
Classification of (Gain) Loss Recognized
 
2016
 
2015
Commodity derivatives
 
 
 
 
Gathering, processing, and marketing sales (1)
 
$
2

 
$
—

(Gains) losses on derivatives, net
 
(28
)
 
(53
)
Interest-rate derivatives
 
 
 
 
(Gains) losses on derivatives, net
 
325

 
205

Total (gains) losses on derivatives, net
 
$
299

 
$
152

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

6. Derivative Instruments (Continued)

Credit-Risk Considerations  The financial integrity of exchange-traded contracts, which are subject to nominal credit risk, is assured by NYMEX or ICE through systems of financial safeguards and transaction guarantees. Over-the-counter traded swaps, options, and futures contracts expose the Company to counterparty credit risk. The Company monitors the creditworthiness of its counterparties, establishes credit limits according to the Company’s credit policies and guidelines, and assesses the impact on the fair value of its counterparties’ creditworthiness. The Company has the ability to require cash collateral or letters of credit to mitigate its credit-risk exposure.
The Company has netting agreements with financial institutions that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities, and routinely exercises its contractual right to offset gains and losses when settling with derivative counterparties. In addition, the Company has setoff agreements with certain financial institutions that may be exercised in the event of default and provide for contract termination and net settlement across derivative types. At March 31, 2016, $238 million of the Company’s $1.758 billion gross derivative liability balance, and at December 31, 2015, $347 million of the Company’s $1.722 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 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 a level that is below investment grade. In February 2016, Moody’s Investors Service (Moody’s) downgraded the Company’s long-term debt credit rating from “Baa2” to “Ba1,” which is below investment grade. The downgrade triggered credit-risk-related features with certain derivative counterparties and required the Company to post collateral under its derivative instruments. The amount of cash posted as collateral pursuant to the contractual requirements applicable to derivative instruments with financial institutions was $420 million at March 31, 2016, and $58 million at December 31, 2015. No counterparties have requested termination or full settlement of derivative positions. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was $1.1 billion (net of collateral) at March 31, 2016, and $1.3 billion (net of collateral) at December 31, 2015.

6. Derivative Instruments (Continued)

Fair Value  Fair value of futures contracts is based on unadjusted quoted prices in active markets for identical assets or liabilities, which represent Level 1 inputs. Valuations of physical-delivery purchase and sale agreements, over-the-counter financial swaps, and commodity option collars are based on similar transactions observable in active markets and industry-standard models that primarily rely on market-observable inputs. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. Inputs used to estimate the fair value of swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and, for Black-Scholes option valuations, discount factors and implied market volatility.
The following summarizes the fair value of the Company’s derivative assets and liabilities by input level within the fair-value hierarchy:
millions
 
 
 
 
 
 
 
 
 
 
 
March 31, 2016
Level 1
 
Level 2
 
Level 3
 
Netting (1)
 
Collateral
 
Total
Assets
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
1

 
$
328

 
$
—

 
$
(116
)
 
$
(1
)
 
$
212

Interest-rate derivatives
—

 
22

 
—

 
—

 
—

 
22

Total derivative assets
$
1

 
$
350

 
$
—

 
$
(116
)
 
$
(1
)
 
$
234

Liabilities
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
—

 
$
(118
)
 
$
—

 
$
116

 
$
—

 
$
(2
)
Interest-rate derivatives
—

 
(1,640
)
 
—

 
—

 
421

 
(1,219
)
Total derivative liabilities
$
—

 
$
(1,758
)
 
$
—

 
$
116

 
$
421

 
$
(1,221
)
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2015
 
 
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
10

 
$
460

 
$
—

 
$
(178
)
 
$
(8
)
 
$
284

Interest-rate derivatives
—

 
56

 
—

 
—

 
—

 
56

Total derivative assets
$
10

 
$
516

 
$
—

 
$
(178
)
 
$
(8
)
 
$
340

Liabilities
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
(1
)
 
$
(179
)
 
$
—

 
$
178

 
$
—

 
$
(2
)
Interest-rate derivatives
—

 
(1,542
)
 
—

 
—

 
58

 
(1,484
)
Total derivative liabilities
$
(1
)
 
$
(1,721
)
 
$
—

 
$
178

 
$
58

 
$
(1,486
)
 __________________________________________________________________
(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.
v3.4.0.3
Tangible Equity Units
 3 Months Ended
Mar. 31, 2016
Tangible Equity Units [Abstract]  
Tangible Equity Units
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 WGP 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. 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 Sheets.

Equity Component  Unless settled earlier at the holder’s option, each purchase contract has a mandatory settlement date of June 7, 2018. Anadarko has a right to elect to issue and deliver shares of Anadarko Petroleum Corporation common stock (APC shares) in lieu of delivering WGP common units at settlement. The Company will deliver not more than 0.8591 WGP common units and not less than 0.7159 WGP common units (or a computed number of APC shares) per TEU on the settlement date, subject to adjustment, at the settlement rate based upon the applicable market value of WGP common units (or APC shares).

Debt Component Each senior amortizing note has an initial principal amount of $10.95 and bears interest at 1.50% per year. On September 7, 2015, Anadarko began paying 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.
v3.4.0.3
Debt and Interest Expense
 3 Months Ended
Mar. 31, 2016
Debt Disclosure [Abstract]  
Debt and Interest Expense
8. Debt and Interest Expense

Debt Activity  The following summarizes the Company’s debt activity, after eliminating the effect of intercompany transactions, during the three months ended March 31, 2016:
 
Carrying Value
 
 
millions
WES
 
WGP (1)
 
Anadarko (2)
 
Anadarko Consolidated
 
Description
Balance at December 31, 2015
$
2,691

 
$
—

 
$
12,957

 
$
15,648

 
 
Issuances
—

 
—

 
794

 
794

 
4.850% Senior Notes due 2021
 
—

 
—

 
1,088

 
1,088

 
5.550% Senior Notes due 2026
 
—

 
—

 
1,088

 
1,088

 
6.600% Senior Notes due 2046
Borrowings
—

 
—

 
1,350

 
1,350

 
364-Day Facility
 
330

 
—

 
—

 
330

 
WES RCF
 
—

 
28

 
—

 
28

 
WGP RCF
Repayments
—

 
—

 
(1,350
)
 
(1,350
)
 
364-Day Facility
 
—

 
—

 
(250
)
 
(250
)
 
Commercial paper notes, net
 
—

 
—

 
(8
)
 
(8
)
 
TEUs - senior amortizing notes
Other, net
—

 
—

 
13

 
13

 
Amortization of discounts, premiums, and debt issuance costs
Balance at March 31, 2016
$
3,021

 
$
28

 
$
15,682

 
$
18,731

 
 
__________________________________________________________________
(1) 
Excludes WES.
(2) 
Excludes WES and WGP.


8. Debt and Interest Expense (Continued)

Debt  The Company’s outstanding debt, excluding the capital lease obligation and any borrowings under the WGP revolving credit facility, is senior unsecured. The following summarizes the Company’s outstanding debt after eliminating the effect of intercompany transactions:
millions
WES
 
WGP (1)
 
Anadarko (2)
 
Anadarko Consolidated
March 31, 2016
 
 
 
 
 
 
 
Total borrowings at face value
$
3,050

 
$
28

 
$
17,333

 
$
20,411

Net unamortized discounts, premiums, and debt issuance costs (3)
(29
)
 
—

 
(1,651
)
 
(1,680
)
Total borrowings
3,021

 
28

 
15,682

 
18,731

Capital lease obligation
—

 
—

 
20

 
20

Less short-term debt
—

 
—

 
3,025

 
3,025

Total long-term debt
$
3,021

 
$
28

 
$
12,677

 
$
15,726

 
 
 
 
 
 
 
 
December 31, 2015
 
 
 
 
 
 
 
Total borrowings at face value
$
2,720

 
$
—

 
$
14,592

 
$
17,312

Net unamortized discounts, premiums, and debt issuance costs (3)
(29
)
 
—

 
(1,635
)
 
(1,664
)
Total borrowings
2,691

 
—

 
12,957

 
15,648

Capital lease obligation
—

 
—

 
20

 
20

Less short-term debt
—

 
—

 
32

 
32

Total long-term debt
$
2,691

 
$
—

 
$
12,945

 
$
15,636

__________________________________________________________________
(1) 
Excludes WES.
(2) 
Excludes WES and WGP.
(3) 
Unamortized discounts, premiums, and debt issuance costs are amortized over the term of the related debt. Debt issuance costs related to revolving credit facilities are included in other current assets and other assets on the Company’s Consolidated Balance Sheets.

Anadarko’s $1.750 billion 5.950% Senior Notes due September 2016 and $1.25 billion of the Company’s $2.0 billion 6.375% Senior Notes due September 2017 were classified as short-term debt on the Company’s Consolidated Balance Sheet at March 31, 2016. The Company used proceeds from its $3.0 billion March 2016 Senior Notes issuances to purchase and retire $1.25 billion of its $2.0 billion Senior Notes in April 2016 pursuant to a tender offer and to redeem the $1.750 billion Senior Notes in May 2016.
Anadarko’s Zero Coupons can be put to the Company in October of each year, in whole or in part, for the then-accreted value, which will be $839 million at the next put date in October 2016. Anadarko’s Zero Coupons were classified as long-term debt on the Company’s Consolidated Balance Sheet at March 31, 2016, as the Company has the ability and intent to refinance these obligations using long-term debt, should the put be exercised.

Fair Value  The Company uses a market approach to determine the fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. The estimated fair value of the Company’s total borrowings was $18.9 billion at March 31, 2016, and $15.7 billion at December 31, 2015.

8. Debt and Interest Expense (Continued)

Anadarko Revolving Credit Facilities and Commercial Paper Program  Anadarko has a $3.0 billion five-year senior unsecured revolving credit facility maturing in January 2021 (Five-Year Facility). In addition, in January 2016 the Company replaced its previous $2.0 billion 364-day senior unsecured revolving credit facility with a new $2.0 billion 364-day senior unsecured revolving credit facility (364-Day Facility), on identical terms, that will mature in January 2017. At March 31, 2016, the Company had no outstanding borrowings under the Five-Year Facility or the 364-Day Facility and was in compliance with all covenants contained therein.
In January 2015, the Company initiated a commercial paper program, which allows for 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 may vary, but may not exceed 397 days. In February 2016, Moody’s downgraded the Company’s commercial paper program credit rating, which essentially eliminated the Company’s access to the commercial paper market. As a result, the Company has not issued commercial paper notes since the downgrade. At March 31, 2016, the Company had no outstanding borrowings under the commercial paper program.

WES and WGP Borrowings  At March 31, 2016, WES was in compliance with all covenants contained in its five-year $1.2 billion senior unsecured revolving credit facility maturing in February 2019 (WES RCF), which is expandable to $1.5 billion. At March 31, 2016, WES had outstanding borrowings under its RCF of $630 million at an interest rate of 1.74%, had outstanding letters of credit of $5 million, and had available borrowing capacity of $565 million.
In March 2016, WGP entered into a three-year $250 million senior secured revolving credit facility maturing in March 2019 (WGP RCF), which is expandable to $500 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions. Obligations under the WGP RCF are secured by a first priority lien on all of WGP’s assets (not including the consolidated assets of WES), as well as all equity interests owned by WGP. Borrowings under the WGP RCF bear interest at LIBOR (with a floor of 0%), plus applicable margins ranging from 2.00% to 2.75% depending on WGP’s consolidated leverage ratio, or at a base rate equal to the greatest of (i) the prime rate, (ii) the federal funds rate plus 0.50%, or (iii) LIBOR plus 1.00%, in each case plus applicable margins ranging from 1.00% to 1.75% based upon WGP’s consolidated leverage ratio. At March 31, 2016, WGP was in compliance with all covenants contained in its RCF, had outstanding borrowings under its RCF of $28 million at an interest rate of 2.69%, and had available borrowing capacity of $222 million.

Interest Expense  The following summarizes interest expense:
 
Three Months Ended 
 March 31,
millions
2016
 
2015
Debt and other
$
258

 
$
254

Capitalized interest
(38
)
 
(38
)
Total interest expense
$
220

 
$
216
v3.4.0.3
Income Taxes
 3 Months Ended
Mar. 31, 2016
Income Tax Disclosure [Abstract]  
Income Taxes
9. Income Taxes

The following summarizes income tax expense (benefit) and effective tax rates:
 
Three Months Ended 
 March 31,
millions except percentages
2016
 
2015
Income tax expense (benefit)
$
(383
)
 
$
(1,392
)
Income (loss) before income taxes
(1,381
)
 
(4,628
)
Effective tax rate
28
%
 
30
%


The Company reported a loss before income taxes for the three months ended March 31, 2016 and 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 months ended March 31, 2016 and 2015, was primarily attributable to non-deductible Algerian exceptional profits tax for Algerian income tax purposes, the tax impact from foreign operations, and net changes in uncertain tax positions.
At March 31, 2016, the Company’s Consolidated Balance Sheet included $1.1 billion of income taxes receivable presented in accounts receivable—others.
v3.4.0.3
Conveyance of Future Hard Minerals Royalty Revenues
 3 Months Ended
Mar. 31, 2016
Deferred Revenue Disclosure [Abstract]  
Conveyance Of Future Hard Minerals Royalty Revenues [Text Block]
10. Conveyance of Future Hard Minerals Royalty Revenues

During the first quarter of 2016, the Company conveyed a limited-term nonparticipating royalty interest in certain of its coal and trona leases to a third party for $413 million, net of transaction costs. Such conveyance entitles the third party to receive up to $553 million in future royalty revenue over a period of not less than 10 years and not greater than 15 years. Additionally, such third party is entitled to receive 3% of the aggregate royalties earned during the first 10 years between $800 million and $900 million and 4% of the aggregate royalties earned during the first 10 years that exceed $900 million. Generally, such third party relies solely on the royalty payments to recover its investment and, as such, has the risk of the royalties not being sufficient to recover its investment over the term of the conveyance.
Proceeds from this transaction have been accounted for as deferred revenues and are included in accrued expenses and other long-term liabilities on the Company’s Consolidated Balance Sheet. The deferred revenues will be amortized to other revenues, included in gains (losses) on divestitures and other, net on a unit-of-revenue basis over the term of the agreement. During the first quarter of 2016, the Company amortized $12 million of deferred revenues as a result of this agreement. Proceeds from the transaction and payments to the third party are reported in financing activities in the Company’s Consolidated Statement of Cash Flows.
The third party will receive the first payment for royalties in September 2016. The specified future amounts that the third party expects to receive and the payment timing are subject to change based upon the actual royalties received by the Company during the term of the conveyance. The following summarizes the future amounts, prior to the 3% to 4% of any excess described above, that the third party expects to receive:
millions
 
2016
$
25

2017
50

2018
50

2019
52

2020
56

Later years
320

Total
$
553
v3.4.0.3
Contingencies
 3 Months Ended
Mar. 31, 2016
Contingencies Disclosure [Abstract]  
Contingencies
11. 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, 2015.

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.
Numerous Deepwater Horizon event-related civil lawsuits were filed against BP and other parties, including the Company. Generally, the plaintiffs sought actual damages, punitive damages, declaratory judgment, and/or injunctive relief. This litigation was consolidated into a federal Multidistrict Litigation (MDL) action pending before Judge Carl Barbier in the U.S. District Court for the Eastern District of Louisiana in New Orleans, Louisiana (Louisiana District Court).

BP Consent Decree In July 2015, BP announced a settlement agreement in principle with the U.S. Department of Justice (DOJ) and certain states and local government entities regarding essentially all of the outstanding claims against BP related to the Deepwater Horizon event (BP Settlement) and, in October 2015, lodged a proposed consent decree with the Louisiana District Court. In April 2016, the Louisiana District Court approved the consent decree. As a result of the BP Settlement and approval of the consent decree, all liability relating to OPA-related environmental costs was resolved and all NRD claims and claims by the United States and the Gulf states impacted by the event relating to the MDL action were dismissed. For any remaining claims relating to the MDL action, the Company is fully indemnified by BP against any losses pursuant to the Settlement Agreement. For additional disclosure related to the Deepwater Horizon events, see Note 15—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, 2015.

Penalties and Fines  In December 2010, the DOJ, on behalf of the United States, filed a civil lawsuit in the 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. After previously finding that Anadarko, as a nonoperating investor in the Macondo well, was not culpable with respect to the Deepwater Horizon events, the Louisiana District Court found Anadarko liable for civil penalties under Section 311 of the CWA as a working-interest owner in the Macondo well and entered a judgment of $159.5 million in December 2015. Neither party appealed the decision and the Company paid the penalty in the first quarter of 2016.
v3.4.0.3
Restructuring Charges
 3 Months Ended
Mar. 31, 2016
Restructuring and Related Activities [Abstract]  
Restructuring Charges
12. Restructuring Charges

In the first quarter of 2016, the Company initiated a workforce reduction program to align the size and composition of Anadarko’s workforce with the Company’s expected future operating and capital plans. Employee notifications related to the workforce reduction program were substantially complete by March 31, 2016, and all restructuring charges will be recognized in 2016, with the exception of $10 million of expense for retirement benefits expected to be recognized in the first quarter of 2017. The following summarizes the total expected restructuring charges and the amounts expensed during the first quarter of 2016, which were included in general and administrative expenses in the Company’s Consolidated Statement of Income:
millions
Total Expected Costs
 
Three Months Ended March 31, 2016
Costs by category
 
 
 
Cash severance
$
154

 
$
131

Retirement benefits (1)
203

 
49

Share-based compensation
32

 
23

Total
$
389

 
$
203

__________________________________________________________________
(1) 
Includes termination benefits, curtailments, and settlements. There were no settlements recognized during the three months ended March 31, 2016. See Note 13—Pension Plans and Other Postretirement Benefits.

The following summarizes the changes in the cash severance-related liability included in accounts payable on the Company’s Consolidated Balance Sheet:
millions
2016
Balance at January 1
$
—

Accruals
131

Payments
(79
)
Balance at March 31
$
52
v3.4.0.3
Pension Plans and Other Postretirement Benefits
 3 Months Ended
Mar. 31, 2016
Compensation and Retirement Disclosure [Abstract]  
Pension Plans and Other Postretirement Benefits
13. Pension Plans and Other Postretirement Benefits

The Company has contributory and non-contributory defined-benefit pension plans, which include both qualified and supplemental plans. The Company also provides certain health care and life insurance benefits for certain retired employees. Retiree health care benefits are funded by contributions from the retiree and, in certain circumstances, contributions from the Company. The Company’s retiree life insurance plan is noncontributory. The following summarizes the Company’s pension and other postretirement benefit cost:
 
Pension Benefits
 
Other Benefits
millions
2016
 
2015
 
2016
 
2015
Three Months Ended March 31
 
 
 
 
 
 
 
Service cost
$
26

 
$
30

 
$
1

 
$
3

Interest cost
26

 
25

 
3

 
4

Expected return on plan assets
(27
)
 
(27
)
 
—

 
—

Amortization of net actuarial loss (gain)
8

 
13

 
—

 
—

Amortization of net prior service cost (credit)
—

 
—

 
(6
)
 
—

Termination benefits expense
44

 
—

 
—

 
—

Curtailment expense
8

 
—

 
(3
)
 
—

Net periodic benefit cost
$
85

 
$
41

 
$
(5
)
 
$
7



In the first quarter of 2016, the Company initiated a workforce reduction program that resulted in a remeasurement of its pension and other postretirement benefit obligations. The Company recognized curtailment expense for both the curtailment-related increase in the benefit obligation and a proportionate share of prior service cost from other comprehensive income (loss). The Company also recognized termination benefits expense related to benefit enhancements to certain employees affected by the workforce reduction program. In addition, the remeasurement resulted in increases in the benefit obligation of $146 million for the pension benefit plans and $26 million for the other postretirement benefit plans, with a corresponding decrease in other comprehensive income.
The Company expects to contribute an additional $82 million in 2016 and $23 million in 2017 to unfunded pension plans related to the workforce reduction program. See Note 12—Restructuring Charges.
v3.4.0.3
Stockholders' Equity
 3 Months Ended
Mar. 31, 2016
Stockholders' Equity Note [Abstract]  
Stockholders' Equity
14. 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, TEUs, and WES Series A Preferred units, 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 
 March 31,
millions except per-share amounts
2016
 
2015
Net income (loss)
 
 
 
Net income (loss) attributable to common stockholders
$
(1,034
)
 
$
(3,268
)
Income (loss) effect of TEUs
(1
)
 
—

Less distributions on participating securities
—

 
1

Basic
$
(1,035
)
 
$
(3,269
)
Diluted
$
(1,035
)
 
$
(3,269
)
Shares
 
 
 
Average number of common shares outstanding—basic
509

 
507

Average number of common shares outstanding—diluted
509

 
507

Excluded due to anti-dilutive effect
10

 
11

Net income (loss) per common share
 
 
 
Basic
$
(2.03
)
 
$
(6.45
)
Diluted
$
(2.03
)
 
$
(6.45
)
v3.4.0.3
Accumulated Other Comprehensive Income (Loss)
 3 Months Ended
Mar. 31, 2016
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]  
Accumulated Other Comprehensive Income (Loss)
15. 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, 2015
$
(42
)
 
$
(341
)
 
$
(383
)
Other comprehensive income (loss), before reclassifications
—

 
(105
)
 
(105
)
Reclassifications to Consolidated Statement of Income
2

 
(5
)
 
(3
)
Balance at March 31, 2016
$
(40
)
 
$
(451
)
 
$
(491
)
v3.4.0.3
Noncontrolling Interests
 3 Months Ended
Mar. 31, 2016
Noncontrolling Interest Items [Abstract]  
Noncontrolling Interests
16. Noncontrolling Interests

WGP, a publicly traded consolidated subsidiary, is a limited partnership formed by Anadarko to own partnership interests in WES. At March 31, 2016, 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 formed by Anadarko to acquire, own, develop, and operate midstream assets. During the three months ended March 31, 2016, WES issued 14 million Series A Preferred units to private investors and raised net proceeds of $440 million, and issued 1.3 million common units to the Company. Proceeds were used to acquire interests in Springfield Pipeline LLC from the Company. In April 2016, WES issued an additional eight million Series A Preferred units to private investors, pursuant to the full exercise of an option granted in connection with the initial issuance, and raised net proceeds of $248 million.
Class C units issued to Anadarko will receive quarterly distributions in the form of additional Class C units until the end of 2017, unless WES elects to convert the units to common units earlier or Anadarko elects to extend the conversion date. WES distributed 324 thousand Class C units to Anadarko during the three months ended March 31, 2016, and 498 thousand Class C units to Anadarko during 2015. During 2015, WES issued approximately 874 thousand common units to the public and raised net proceeds of $57 million.
At March 31, 2016, WGP’s ownership interest in WES consisted of a 31.5% limited partner interest, the entire 1.6% general partner interest, and all of the WES incentive distribution rights. At March 31, 2016, Anadarko also owned an 8.7% limited partner interest in WES through other subsidiaries’ ownership of common and Class C units. The remaining 58.2% limited partner interest in WES was owned by the public.
v3.4.0.3
Variable Interest Entities
 3 Months Ended
Mar. 31, 2016
Variable Interest Entities [Abstract]  
Variable Interest Entity Disclosure [Text Block]
17. Variable Interest Entities

Consolidated VIEs The Company determined that the partners in WGP and WES with equity at risk lack the power, through voting rights or similar rights, to direct the activities that most significantly impact WGP’s and WES’s economic performance; therefore, WGP and WES are considered VIEs. Anadarko, through its ownership of the general partner interest in WGP, has the power to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to WGP and WES, therefore Anadarko is considered the primary beneficiary and consolidates WGP and WES. See Note 16—Noncontrolling Interests for additional information on WGP and WES.

Assets and Liabilities of VIEs The assets of WGP and WES cannot be used by Anadarko for general corporate purposes and are both included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets. The carrying amounts of liabilities related to WGP and WES for which the creditors do not have recourse to other assets of the Company are both included in and disclosed parenthetically on the Company’s Consolidated Balance Sheets.
All outstanding debt for WES at March 31, 2016, and December 31, 2015, including any borrowings under the WES RCF, is recourse to WES’s general partner, which in turn has been indemnified in certain circumstances by certain wholly owned subsidiaries of the Company for such liabilities. All outstanding debt for WGP at March 31, 2016, and December 31, 2015, including any borrowings under the WGP RCF, is recourse to WGP’s general partner, which is a wholly owned subsidiary of the Company. See Note 8—Debt and Interest Expense for additional information on WGP and WES long-term debt balances.

VIE Financing WGP’s sources of liquidity include borrowings under its RCF and distributions from WES. WES’s sources of liquidity include cash and cash equivalents, cash flows generated from operations, interest income from a note receivable from Anadarko as discussed below, borrowings under its RCF, the issuance of additional partnership units, or debt offerings. See Note 8—Debt and Interest Expense and Note 16—Noncontrolling Interests for additional information on WGP and WES financing activity.

Financial Support Provided to VIEs Concurrent with the closing of its May 2008 initial public offering, WES loaned the Company $260 million in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The related interest income for WES was $4 million for the three months ended March 31, 2016 and 2015. The note receivable and related interest income is eliminated in consolidation.
In March 2015, WES acquired the Company’s interest in Delaware Basin JV Gathering LLC. The acquisition was financed using a deferred purchase price obligation which requires a cash payment from WES to the Company due on March 31, 2020. The net present value of this obligation was $193 million at March 31, 2016, and $189 million at December 31, 2015.
In order to reduce WES’s exposure to a majority of the commodity-price risk inherent in certain of their contracts, Anadarko has commodity price swap agreements in place with WES expiring in 2016. WES has recorded a capital contribution from Anadarko in its Consolidated Statement of Equity and Partners’ Capital for the amount by which the swap price exceeds the applicable market price. WES recorded a $4 million capital contribution from Anadarko for the three months ended March 31, 2016, and a capital contribution of zero for the three months ended March 31, 2015.
v3.4.0.3
Supplemental Cash Flow Information
 3 Months Ended
Mar. 31, 2016
Supplemental Cash Flow Information [Abstract]  
Supplemental Cash Flow Information
18. Supplemental Cash Flow Information

The following summarizes cash paid (received) for interest and income taxes, as well as non-cash investing and financing activities:
 
Three Months Ended 
 March 31,
millions
2016
 
2015
Cash paid (received)
 
 
 
Interest, net of amounts capitalized (1)
$
299

 
$
1,532

Income taxes, net of refunds
(8
)
 
(5
)
Non-cash investing activities
 
 
 
Fair value of properties and equipment from non-cash transactions
$
—

 
$
54

Asset retirement cost additions
27

 
63

Accruals of property, plant, and equipment
623

 
1,080

Net liabilities assumed (divested) in acquisitions and divestitures
—

 
19

Non-cash investing and financing activities
 
 
 
Floating production, storage, and offloading vessel construction period obligation
$
2

 
$
25

__________________________________________________________________
(1) 
Includes $1.2 billion of interest related to the Tronox settlement payment in 2015.
v3.4.0.3
Segment Information
 3 Months Ended
Mar. 31, 2016
Segment Reporting [Abstract]  
Segment Information
19. 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 oil, condensate, natural gas, 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, condensate, 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; gains (losses) on divestitures, net; 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 (loss) attributable to noncontrolling interests. During the periods presented, items not related to the Company’s normal operations included restructuring charges related to the workforce reduction program included in general and administrative expenses, other operating expenses such as 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 gains (losses) on divestitures, net and exploration expense as they are not indicators 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 (loss) attributable to noncontrolling interests is excluded from the Company’s measure of Adjusted EBITDAX because it represents earnings that are not attributable to the Company’s common stockholders.
Management believes 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 
 March 31,
millions
2016
 
2015
Income (loss) before income taxes
$
(1,381
)
 
$
(4,628
)
(Gains) losses on divestitures, net
(2
)
 
334

Exploration expense
126

 
1,083

DD&A
1,149

 
1,256

Impairments
16

 
2,783

Interest expense
220

 
216

Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives
404

 
243

Restructuring charges
203

 
—

Other operating expense
1

 
4

Tronox-related contingent loss
—

 
5

Certain other nonoperating items
—

 
22

Less net income (loss) attributable to noncontrolling interests
36

 
32

Consolidated Adjusted EBITDAX
$
700

 
$
1,286


19. 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 March 31, 2016
 
 
 
 
 
 
 
 
 
Sales revenues
$
711

 
$
125

 
$
798

 
$
—

 
$
1,634

Intersegment revenues
601

 
302

 
(663
)
 
(240
)
 
—

Other
—

 
—

 
—

 
38

 
38

Total revenues and other (1)
1,312

 
427

 
135

 
(202
)
 
1,672

Operating costs and expenses (2)
773

 
183

 
176

 
(89
)
 
1,043

Net cash from settlement of commodity derivatives
—

 
—

 
—

 
(103
)
 
(103
)
Other (income) expense, net
—

 
—

 
—

 
—

 
—

Net income (loss) attributable to noncontrolling interests
—

 
36

 
—

 
—

 
36

Total expenses and other
773

 
219

 
176

 
(192
)
 
976

Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement
—

 
—

 
4

 
—

 
4

Adjusted EBITDAX
$
539

 
$
208

 
$
(37
)
 
$
(10
)
 
$
700

 
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2015
 
 
 
 
 
 
 
 
 
Sales revenues
$
1,070

 
$
174

 
$
1,341

 
$
—

 
$
2,585

Intersegment revenues
1,117

 
302

 
(1,191
)
 
(228
)
 
—

Other
—

 
—

 
—

 
70

 
70

Total revenues and other (1)
2,187

 
476

 
150

 
(158
)
 
2,655

Operating costs and expenses (2)
1,002

 
240

 
198

 
(37
)
 
1,403

Net cash from settlement of commodity derivatives
—

 
—

 
—

 
(90
)
 
(90
)
Other (income) expense, net (3)
—

 
—

 
—

 
25

 
25

Net income (loss) attributable to noncontrolling interests
—

 
32

 
—

 
—

 
32

Total expenses and other
1,002

 
272

 
198

 
(102
)
 
1,370

Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement
—

 
—

 
1

 
—

 
1

Adjusted EBITDAX
$
1,185

 
$
204

 
$
(47
)
 
$
(56
)
 
$
1,286

 __________________________________________________________________
(1) 
Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.
(2) 
Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and other operating expense since these expenses are excluded from Adjusted EBITDAX.
(3) 
Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.
v3.4.0.3
Summary of Significant Accounting Policies (Policies)
 3 Months Ended
Mar. 31, 2016
Accounting Policies [Abstract]  
Use of Estimates
Use of Estimates  The preparation of financial statements in accordance with GAAP 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
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 require capitalized debt issuance 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. The Company adopted these ASUs on January 1, 2016, using a retrospective approach. The adoption resulted in a reclassification that reduced other current assets and short-term debt by $1 million and reduced other assets and long-term debt by $82 million on the Company’s Consolidated Balance Sheet at December 31, 2015.
The FASB issued ASU 2015-02, Consolidation (Topic 810)—Amendments to the Consolidation Analysis. The Company adopted this ASU on January 1, 2016. In accordance with the new ASU, Western Gas Equity Partners, LP (WGP) and Western Gas Partners, LP (WES), publicly traded consolidated subsidiaries of the Company, are considered VIEs for which the Company is the primary beneficiary. Prior to adoption of the ASU, WGP and WES were consolidated by the Company under the voting interest model and, after adoption, the Company will continue to consolidate WGP and WES under the variable interest model. While this ASU requires additional financial statement disclosure, it has no impact on the Company’s consolidated results of operations, cash flows, or financial position. See Note 17—Variable Interest Entities.
1. Summary of Significant Accounting Policies (Continued)

The FASB issued ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. This ASU will simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This ASU is effective for annual and interim periods beginning in 2017 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 2016-02, Leases (Topic 842). This ASU requires the lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet and disclose key information about their leasing transactions. This ASU is effective for annual and interim periods beginning in 2019. The Company is evaluating the impact of the adoption of this ASU on its consolidated financial statements.
The FASB issued ASU 2016-01, Financial Instruments—Overall: Recognition and Measurement of Financial Assets and Financial Liabilities (Subtopic 825-10). This ASU amends existing requirements on the classification and measurement of financial instruments. Changes to the current requirements primarily affect the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. This ASU is effective for annual periods beginning in 2018 with early adoption of certain provisions 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 (Topic 606), ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), and ASU 2016-10, Revenues from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, which supersede 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 require an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Company is required to adopt the new standards in the first quarter of 2018 using one of two retrospective application methods. The Company is continuing to evaluate the provisions of these ASUs, and has not determined the impact these standards may have on its consolidated financial statements and related disclosures or decided upon the method of adoption.
v3.4.0.3
Inventories (Tables)
 3 Months Ended
Mar. 31, 2016
Energy Related Inventory [Abstract]  
Inventory Disclosure Table
The following summarizes the major classes of inventories included in other current assets:
millions
March 31,
2016
 
December 31,
2015
Oil
$
96

 
$
116

Natural gas
25

 
36

NGLs
67

 
64

Total inventories
$
188

 
$
216
v3.4.0.3
Impairments (Tables)
 3 Months Ended
Mar. 31, 2016
Asset Impairment Charges [Abstract]  
Schedule of Impairment Expense
The following summarizes impairments of long-lived assets and the related post-impairment fair values by segment:
  
Three Months Ended
millions
Impairment
 
Fair Value (1)
March 31, 2016
 
 
 
Oil and gas exploration and production
 
 
 
Long-lived assets held for use
 
 
 
U.S. onshore properties
$
4

 
$
585

Gulf of Mexico properties
1

 
—

Cost-method investment (2)
1

 
32

Midstream
 
 
 
Long-lived assets held for use
10

 
3

Total
$
16

 
$
620

 
 
 
 
March 31, 2015
 
 
 
Oil and gas exploration and production
 
 
 
Long-lived assets held for use
 
 
 
U.S. onshore properties
$
2,307

 
$
1,299

Midstream
 
 
 
Long-lived assets held for use
476

 
206

Total
$
2,783

 
$
1,505


__________________________________________________________________
(1) 
Measured as of the impairment date using the income approach and Level 3 inputs.
(2) 
Represents the after-tax net investment.
v3.4.0.3
Derivative Instruments (Tables)
 3 Months Ended
Mar. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Schedule of Derivative Instruments
The following is a summary of the Company’s derivative instruments related to oil and natural-gas production/processing derivative activities at March 31, 2016:
 
2016
Settlement
Oil
 
Three-Way Collars (MBbls/d)
83

Average price per barrel
 
Ceiling sold price (call)
$
63.82

Floor purchased price (put)
$
54.46

Floor sold price (put)
$
42.77

Natural Gas
 
Fixed-Price Contracts (thousand MMBtu/d)
43

Average price per MMBtu
$
2.24

NGLs
 
Fixed-Price Contracts (MBbls/d)
4

Average price per barrel
$
12.93

__________________________________________________________________
MBbls/d—thousand barrels per day
MMBtu/d—million British thermal units per day
MMBtu—million British thermal units



The Company had the following outstanding interest-rate swaps at March 31, 2016: 
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%
$
500

 
 
September 2016 – 2046
 
September 2018
 
6.559%
$
300

 
 
September 2016 – 2046
 
September 2020
 
6.509%
$
450

 
 
September 2017 – 2047
 
September 2018
 
6.445%
$
100

 
 
September 2017 – 2047
 
September 2020
 
6.891%
$
250

 
 
September 2017 – 2047
 
September 2021
 
6.570%
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location
The following summarizes the fair value of the Company’s derivative instruments:

 
 
Gross Derivative Assets
 
Gross Derivative Liabilities
millions
 
March 31,
 
December 31,
 
March 31,
 
December 31,
Balance Sheet Classification
 
2016
 
2015
 
2016
 
2015
Commodity derivatives
 
 
 
 
 
 
 
 
Other current assets
 
$
322

 
$
462

 
$
(116
)
 
$
(177
)
Other assets
 
7

 
8

 
—

 
—

Accrued expenses
 
—

 
—

 
(2
)
 
(3
)
 
 
329

 
470

 
(118
)
 
(180
)
Interest-rate derivatives
 
 
 
 
 
 
 
 
Other current assets
 
2

 
2

 
—

 
—

Other assets
 
20

 
54

 
—

 
—

Accrued expenses
 
—

 
—

 
(90
)
 
(54
)
Other liabilities
 
—

 
—

 
(1,550
)
 
(1,488
)
 
 
22

 
56

 
(1,640
)
 
(1,542
)
Total derivatives
 
$
351

 
$
526

 
$
(1,758
)
 
$
(1,722
)

The following summarizes gains and losses related to derivative instruments:
millions
 
Three Months Ended 
 March 31,
Classification of (Gain) Loss Recognized
 
2016
 
2015
Commodity derivatives
 
 
 
 
Gathering, processing, and marketing sales (1)
 
$
2

 
$
—

(Gains) losses on derivatives, net
 
(28
)
 
(53
)
Interest-rate derivatives
 
 
 
 
(Gains) losses on derivatives, net
 
325

 
205

Total (gains) losses on derivatives, net
 
$
299

 
$
152

__________________________________________________________________
(1) 
Represents the effect of Marketing and Trading Derivative Activities.
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis
The following summarizes the fair value of the Company’s derivative assets and liabilities by input level within the fair-value hierarchy:
millions
 
 
 
 
 
 
 
 
 
 
 
March 31, 2016
Level 1
 
Level 2
 
Level 3
 
Netting (1)
 
Collateral
 
Total
Assets
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
1

 
$
328

 
$
—

 
$
(116
)
 
$
(1
)
 
$
212

Interest-rate derivatives
—

 
22

 
—

 
—

 
—

 
22

Total derivative assets
$
1

 
$
350

 
$
—

 
$
(116
)
 
$
(1
)
 
$
234

Liabilities
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
—

 
$
(118
)
 
$
—

 
$
116

 
$
—

 
$
(2
)
Interest-rate derivatives
—

 
(1,640
)
 
—

 
—

 
421

 
(1,219
)
Total derivative liabilities
$
—

 
$
(1,758
)
 
$
—

 
$
116

 
$
421

 
$
(1,221
)
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2015
 
 
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
10

 
$
460

 
$
—

 
$
(178
)
 
$
(8
)
 
$
284

Interest-rate derivatives
—

 
56

 
—

 
—

 
—

 
56

Total derivative assets
$
10

 
$
516

 
$
—

 
$
(178
)
 
$
(8
)
 
$
340

Liabilities
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
(1
)
 
$
(179
)
 
$
—

 
$
178

 
$
—

 
$
(2
)
Interest-rate derivatives
—

 
(1,542
)
 
—

 
—

 
58

 
(1,484
)
Total derivative liabilities
$
(1
)
 
$
(1,721
)
 
$
—

 
$
178

 
$
58

 
$
(1,486
)
 __________________________________________________________________
(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.
v3.4.0.3
Debt and Interest Expense (Tables)
 3 Months Ended
Mar. 31, 2016
Debt Disclosure [Abstract]  
Debt Outstanding and Debt Activity Tables
The following summarizes the Company’s debt activity, after eliminating the effect of intercompany transactions, during the three months ended March 31, 2016:
 
Carrying Value
 
 
millions
WES
 
WGP(1)
 
Anadarko (2)
 
Anadarko Consolidated
 
Description
Balance at December 31, 2015
$
2,691

 
$
—

 
$
12,957

 
$
15,648

 
 
Issuances
—

 
—

 
794

 
794

 
4.850% Senior Notes due 2021
 
—

 
—

 
1,088

 
1,088

 
5.550% Senior Notes due 2026
 
—

 
—

 
1,088

 
1,088

 
6.600% Senior Notes due 2046
Borrowings
—

 
—

 
1,350

 
1,350

 
364-Day Facility
 
330

 
—

 
—

 
330

 
WES RCF
 
—

 
28

 
—

 
28

 
WGP RCF
Repayments
—

 
—

 
(1,350
)
 
(1,350
)
 
364-Day Facility
 
—

 
—

 
(250
)
 
(250
)
 
Commercial paper notes, net
 
—

 
—

 
(8
)
 
(8
)
 
TEUs - senior amortizing notes
Other, net
—

 
—

 
13

 
13

 
Amortization of discounts, premiums,
and debt issuance costs
Balance at March 31, 2016
$
3,021

 
$
28

 
$
15,682

 
$
18,731

 
 
__________________________________________________________________
(1) 
Excludes WES.
(2) 
Excludes WES and WGP.


The following summarizes the Company’s outstanding debt after eliminating the effect of intercompany transactions:
millions
WES
 
WGP(1)
 
Anadarko(2)
 
Anadarko Consolidated
March 31, 2016
 
 
 
 
 
 
 
Total borrowings at face value
$
3,050

 
$
28

 
$
17,333

 
$
20,411

Net unamortized discounts, premiums, and
debt issuance costs (3)
(29
)
 
—

 
(1,651
)
 
(1,680
)
Total borrowings
3,021

 
28

 
15,682

 
18,731

Capital lease obligation
—

 
—

 
20

 
20

Less short-term debt
—

 
—

 
3,025

 
3,025

Total long-term debt
$
3,021

 
$
28

 
$
12,677

 
$
15,726

 
 
 
 
 
 
 
 
December 31, 2015
 
 
 
 
 
 
 
Total borrowings at face value
$
2,720

 
$
—

 
$
14,592

 
$
17,312

Net unamortized discounts, premiums, and
debt issuance costs (3)
(29
)
 
—

 
(1,635
)
 
(1,664
)
Total borrowings
2,691

 
—

 
12,957

 
15,648

Capital lease obligation
—

 
—

 
20

 
20

Less short-term debt
—

 
—

 
32

 
32

Total long-term debt
$
2,691

 
$
—

 
$
12,945

 
$
15,636

__________________________________________________________________
(1) 
Excludes WES.
(2) 
Excludes WES and WGP.
(3) 
Unamortized discounts, premiums, and debt issuance costs are amortized over the term of the related debt. Debt issuance costs related to revolving credit facilities are included in other current assets and other assets on the Company’s Consolidated Balance Sheets.
Interest Expense Table
The following summarizes interest expense:
 
Three Months Ended 
 March 31,
millions
2016
 
2015
Debt and other
$
258

 
$
254

Capitalized interest
(38
)
 
(38
)
Total interest expense
$
220

 
$
216
v3.4.0.3
Income Taxes (Tables)
 3 Months Ended
Mar. 31, 2016
Income Tax Disclosure [Abstract]  
Schedule of Income Taxes and Effective Tax Rate
The following summarizes income tax expense (benefit) and effective tax rates:
 
Three Months Ended 
 March 31,
millions except percentages
2016
 
2015
Income tax expense (benefit)
$
(383
)
 
$
(1,392
)
Income (loss) before income taxes
(1,381
)
 
(4,628
)
Effective tax rate
28
%
 
30
%
v3.4.0.3
Conveyance of Future Hard Minerals Royalty Revenues (Tables)
 3 Months Ended
Mar. 31, 2016
Deferred Revenue Disclosure [Abstract]  
Other Commitments [Table Text Block]
The following summarizes the future amounts, prior to the 3% to 4% of any excess described above, that the third party expects to receive:
millions
 
2016
$
25

2017
50

2018
50

2019
52

2020
56

Later years
320

Total
$
553
v3.4.0.3
Restructuring Charges (Tables)
 3 Months Ended
Mar. 31, 2016
Restructuring and Related Activities [Abstract]  
Schedule of Restructuring Charges
The following summarizes the total expected restructuring charges and the amounts expensed during the first quarter of 2016, which were included in general and administrative expenses in the Company’s Consolidated Statement of Income:
millions
Total Expected Costs
 
Three Months Ended March 31, 2016
Costs by category
 
 
 
Cash severance
$
154

 
$
131

Retirement benefits (1)
203

 
49

Share-based compensation
32

 
23

Total
$
389

 
$
203

__________________________________________________________________
(1) 
Includes termination benefits, curtailments, and settlements. There were no settlements recognized during the three months ended March 31, 2016. See Note 13—Pension Plans and Other Postretirement Benefits.

The following summarizes the changes in the cash severance-related liability included in accounts payable on the Company’s Consolidated Balance Sheet:
millions
2016
Balance at January 1
$
—

Accruals
131

Payments
(79
)
Balance at March 31
$
52
v3.4.0.3
Pension Plans and Other Postretirement Benefits (Tables)
 3 Months Ended
Mar. 31, 2016
Compensation and Retirement Disclosure [Abstract]  
Components of Net Periodic Benefit Cost Table
The following summarizes the Company’s pension and other postretirement benefit cost:
 
Pension Benefits
 
Other Benefits
millions
2016
 
2015
 
2016
 
2015
Three Months Ended March 31
 
 
 
 
 
 
 
Service cost
$
26

 
$
30

 
$
1

 
$
3

Interest cost
26

 
25

 
3

 
4

Expected return on plan assets
(27
)
 
(27
)
 
—

 
—

Amortization of net actuarial loss (gain)
8

 
13

 
—

 
—

Amortization of net prior service cost (credit)
—

 
—

 
(6
)
 
—

Termination benefits expense
44

 
—

 
—

 
—

Curtailment expense
8

 
—

 
(3
)
 
—

Net periodic benefit cost
$
85

 
$
41

 
$
(5
)
 
$
7
v3.4.0.3
Stockholders' Equity (Tables)
 3 Months Ended
Mar. 31, 2016
Stockholders' Equity Note [Abstract]  
Earnings Per Share Table
The following provides a reconciliation between basic and diluted earnings per share attributable to common stockholders:
 
Three Months Ended 
 March 31,
millions except per-share amounts
2016
 
2015
Net income (loss)
 
 
 
Net income (loss) attributable to common stockholders
$
(1,034
)
 
$
(3,268
)
Income (loss) effect of TEUs
(1
)
 
—

Less distributions on participating securities
—

 
1

Basic
$
(1,035
)
 
$
(3,269
)
Diluted
$
(1,035
)
 
$
(3,269
)
Shares
 
 
 
Average number of common shares outstanding—basic
509

 
507

Average number of common shares outstanding—diluted
509

 
507

Excluded due to anti-dilutive effect
10

 
11

Net income (loss) per common share
 
 
 
Basic
$
(2.03
)
 
$
(6.45
)
Diluted
$
(2.03
)
 
$
(6.45
)
v3.4.0.3
Accumulated Other Comprehensive Income (Loss) (Tables)
 3 Months Ended
Mar. 31, 2016
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]  
Schedule Of 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, 2015
$
(42
)
 
$
(341
)
 
$
(383
)
Other comprehensive income (loss), before reclassifications
—

 
(105
)
 
(105
)
Reclassifications to Consolidated Statement of Income
2

 
(5
)
 
(3
)
Balance at March 31, 2016
$
(40
)
 
$
(451
)
 
$
(491
)
v3.4.0.3
Supplemental Cash Flow Information (Tables)
 3 Months Ended
Mar. 31, 2016
Supplemental Cash Flow Information [Abstract]  
Supplemental Cash Flow Table
The following summarizes cash paid (received) for interest and income taxes, as well as non-cash investing and financing activities:
 
Three Months Ended 
 March 31,
millions
2016
 
2015
Cash paid (received)
 
 
 
Interest, net of amounts capitalized (1)
$
299

 
$
1,532

Income taxes, net of refunds
(8
)
 
(5
)
Non-cash investing activities
 
 
 
Fair value of properties and equipment from non-cash transactions
$
—

 
$
54

Asset retirement cost additions
27

 
63

Accruals of property, plant, and equipment
623

 
1,080

Net liabilities assumed (divested) in acquisitions and divestitures
—

 
19

Non-cash investing and financing activities
 
 
 
Floating production, storage, and offloading vessel construction period obligation
$
2

 
$
25

__________________________________________________________________
(1) 
Includes $1.2 billion of interest related to the Tronox settlement payment in 2015.
v3.4.0.3
Segment Information (Tables)
 3 Months Ended
Mar. 31, 2016
Segment Reporting [Abstract]  
Reconciliation of Consolidated Adjusted EBITDAX to Income (Loss) Before Income Taxes
Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes:
 
Three Months Ended 
 March 31,
millions
2016
 
2015
Income (loss) before income taxes
$
(1,381
)
 
$
(4,628
)
(Gains) losses on divestitures, net
(2
)
 
334

Exploration expense
126

 
1,083

DD&A
1,149

 
1,256

Impairments
16

 
2,783

Interest expense
220

 
216

Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives
404

 
243

Restructuring charges
203

 
—

Other operating expense
1

 
4

Tronox-related contingent loss
—

 
5

Certain other nonoperating items
—

 
22

Less net income (loss) attributable to noncontrolling interests
36

 
32

Consolidated Adjusted EBITDAX
$
700

 
$
1,286
Schedule of Segment Reporting Information, by Segment
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 March 31, 2016
 
 
 
 
 
 
 
 
 
Sales revenues
$
711

 
$
125

 
$
798

 
$
—

 
$
1,634

Intersegment revenues
601

 
302

 
(663
)
 
(240
)
 
—

Other
—

 
—

 
—

 
38

 
38

Total revenues and other (1)
1,312

 
427

 
135

 
(202
)
 
1,672

Operating costs and expenses (2)
773

 
183

 
176

 
(89
)
 
1,043

Net cash from settlement of commodity derivatives
—

 
—

 
—

 
(103
)
 
(103
)
Other (income) expense, net
—

 
—

 
—

 
—

 
—

Net income (loss) attributable to noncontrolling interests
—

 
36

 
—

 
—

 
36

Total expenses and other
773

 
219

 
176

 
(192
)
 
976

Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement
—

 
—

 
4

 
—

 
4

Adjusted EBITDAX
$
539

 
$
208

 
$
(37
)
 
$
(10
)
 
$
700

 
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2015
 
 
 
 
 
 
 
 
 
Sales revenues
$
1,070

 
$
174

 
$
1,341

 
$
—

 
$
2,585

Intersegment revenues
1,117

 
302

 
(1,191
)
 
(228
)
 
—

Other
—

 
—

 
—

 
70

 
70

Total revenues and other (1)
2,187

 
476

 
150

 
(158
)
 
2,655

Operating costs and expenses (2)
1,002

 
240

 
198

 
(37
)
 
1,403

Net cash from settlement of commodity derivatives
—

 
—

 
—

 
(90
)
 
(90
)
Other (income) expense, net (3)
—

 
—

 
—

 
25

 
25

Net income (loss) attributable to noncontrolling interests
—

 
32

 
—

 
—

 
32

Total expenses and other
1,002

 
272

 
198

 
(102
)
 
1,370

Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement
—

 
—

 
1

 
—

 
1

Adjusted EBITDAX
$
1,185

 
$
204

 
$
(47
)
 
$
(56
)
 
$
1,286

 __________________________________________________________________
(1) 
Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.
(2) 
Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and other operating expense since these expenses are excluded from Adjusted EBITDAX.
(3) 
Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.
v3.4.0.3
Summary of Significant Accounting Policies (Detail) - USD ($)
$ in Millions
Mar. 31, 2016
Dec. 31, 2015
New Accounting Pronouncements or Change in Accounting Principle [Line Items]    
Other current assets $ 428 $ 573
Short-term debt 3,025 32
Other Assets 2,304 2,268
Long-term Debt $ 15,726 15,636
Accounting Standards Update 2015-03 And 2015-15 [Member] | Restatement Adjustment [Member]    
New Accounting Pronouncements or Change in Accounting Principle [Line Items]    
Other current assets   1
Short-term debt   1
Other Assets   82
Long-term Debt   $ 82
v3.4.0.3
Inventories (Detail) - USD ($)
$ in Millions
Mar. 31, 2016
Dec. 31, 2015
Energy Related Inventory [Abstract]    
Oil $ 96 $ 116
Natural gas 25 36
NGLs 67 64
Total inventories $ 188 $ 216
v3.4.0.3
Assets Held for Sale (Detail) - USD ($)
$ in Millions
 1 Months Ended 3 Months Ended
Apr. 30, 2016
Mar. 31, 2016
Mar. 31, 2015
Property, Plant, and Equipment [Line Items]      
Sales price, subject to closing adjustments   $ 35 $ 22
Held for Sale [Member]      
Property, Plant, and Equipment [Line Items]      
Assets associated with assets held for sale were not material    
Liabilities associated with assets held for sale were not material    
Oil and Gas Exploration and Production Reporting Segment [Member] | Asset Disposed of by Sale [Member] | Certain U.S. Onshore East Texas Assets [Member] | Subsequent Event [Member]      
Property, Plant, and Equipment [Line Items]      
Sales price, subject to closing adjustments $ 107    
v3.4.0.3
Impairments - Impairments and Fair Values by Segment Table (Detail) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Impaired Long Lived Assets Held and Used [Line Items]    
Total impairments $ 16 $ 2,783
Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member]    
Impaired Long Lived Assets Held and Used [Line Items]    
Total fair value [1] 620 1,505
Oil and Gas Exploration and Production Reporting Segment [Member]    
Impaired Long Lived Assets Held and Used [Line Items]    
Impairment of cost-method investment 1  
Oil and Gas Exploration and Production Reporting Segment [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member]    
Impaired Long Lived Assets Held and Used [Line Items]    
Fair value of cost-method investment [1],[2] 32  
Oil and Gas Exploration and Production Reporting Segment [Member] | U.S. Onshore Properties [Member]    
Impaired Long Lived Assets Held and Used [Line Items]    
Impairment of long-lived assets held for use 4 2,307
Oil and Gas Exploration and Production Reporting Segment [Member] | U.S. Onshore Properties [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member]    
Impaired Long Lived Assets Held and Used [Line Items]    
Fair value of long-lived assets held for use [1] 585 1,299
Oil and Gas Exploration and Production Reporting Segment [Member] | Gulf of Mexico [Member]    
Impaired Long Lived Assets Held and Used [Line Items]    
Impairment of long-lived assets held for use 1  
Oil and Gas Exploration and Production Reporting Segment [Member] | Gulf of Mexico [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member]    
Impaired Long Lived Assets Held and Used [Line Items]    
Fair value of long-lived assets held for use [1] 0  
Midstream Reporting Segment [Member]    
Impaired Long Lived Assets Held and Used [Line Items]    
Impairment of long-lived assets held for use 10 476
Midstream Reporting Segment [Member] | Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Income Approach Valuation Technique [Member]    
Impaired Long Lived Assets Held and Used [Line Items]    
Fair value of long-lived assets held for use [1] $ 3 $ 206
[1] Measured as of the impairment date using the income approach and Level 3 inputs.
[2] Represents the after-tax net investment.
v3.4.0.3
Impairments - Additional Information (Detail) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Dec. 31, 2015
Property, Plant, and Equipment [Line Items]      
Impairment of unproved properties $ 35 $ 1,009  
Net book value 33,526   $ 33,751
Unproved Greater Natural Buttes Properties [Member]      
Property, Plant, and Equipment [Line Items]      
Impairment of unproved properties   $ 935  
Depletion Group At Risk For Impairment [Member]      
Property, Plant, and Equipment [Line Items]      
Net book value 2,100    
Potential non-cash impairments that could be recognized in the future, in excess of $ 1,000    
v3.4.0.3
Suspended Exploratory Well Costs (Detail) - USD ($)
$ in Billions
 3 Months Ended
Mar. 31, 2016
Dec. 31, 2015
Capitalized Exploratory Well Costs [Abstract]    
Suspended exploratory well costs $ 1.1 $ 1.1
Suspended exploratory well costs previously capitalized for a period greater than one year since the completion of drilling at December 31, 2015, charged to exploration expense were not material  
v3.4.0.3
Derivative Instruments - Oil and Natural-Gas Production/Processing Derivative Activities Table (Detail) - Not Designated as Hedging Instrument [Member] - Price Risk Derivative [Member]
MMBTU / d in Thousands
 3 Months Ended
Mar. 31, 2016
MMBTU / d
MBbls / d
$ / bbl
$ / MMBTU
Three Way Collars Oil 2016 [Member]  
Derivative [Line Items]  
Oil or NGL derivative nonmonetary notional amount per day | MBbls / d 83
Three Way Collars Oil 2016 [Member] | Call Option [Member] | Short [Member]  
Average price per MMBtu or barrel  
Average ceiling price 63.82
Three Way Collars Oil 2016 [Member] | Put Option [Member] | Short [Member]  
Average price per MMBtu or barrel  
Average floor price 42.77
Three Way Collars Oil 2016 [Member] | Put Option [Member] | Long [Member]  
Average price per MMBtu or barrel  
Average floor price 54.46
Forward Contracts Natural Gas 2016 [Member]  
Average price per MMBtu or barrel  
Natural-gas derivative nonmonetary notional amount per day | MMBTU / d 43
Average price per MMBtu or barrel | $ / MMBTU 2.24
Forward Contracts NGLs 2016 [Member]  
Derivative [Line Items]  
Oil or NGL derivative nonmonetary notional amount per day | MBbls / d 4
Average price per MMBtu or barrel  
Average price per MMBtu or barrel 12.93
v3.4.0.3
Derivative Instruments - Additional Information (Detail)
Mcf in Millions
 3 Months Ended 12 Months Ended
May. 02, 2016
USD ($)
Apr. 25, 2016
USD ($)
Mar. 31, 2016
USD ($)
Mcf
Mar. 31, 2015
USD ($)
Dec. 31, 2015
USD ($)
Mcf
Derivative [Line Items]          
Debt instrument, principal amount     $ 20,411,000,000   $ 17,312,000,000
Net cash paid in settlement of derivative instruments     105,000,000 $ 91,000,000  
Anadarko Excluding WES and WGP [Member]          
Derivative [Line Items]          
Debt instrument, principal amount [1]     17,333,000,000   14,592,000,000
Senior Notes 1 Through 3 [Member] | Anadarko Excluding WES and WGP [Member] | Senior Notes [Member]          
Derivative [Line Items]          
Debt instrument, principal amount     $ 3,000,000,000    
5.950% Senior Notes Due 2016 [Member] | Anadarko Excluding WES and WGP [Member] | Senior Notes [Member]          
Derivative [Line Items]          
Debt instrument, stated interest rate     5.95%    
Debt instrument, maturity date     Sep. 15, 2016    
5.950% Senior Notes Due 2016 [Member] | Anadarko Excluding WES and WGP [Member] | Subsequent Event [Member] | Senior Notes [Member]          
Derivative [Line Items]          
Senior notes redeemed $ 1,750,000,000        
Debt instrument, stated interest rate 5.95%        
Debt instrument, maturity date Sep. 15, 2016        
6.375% Senior Notes Due 2017 [Member] | Anadarko Excluding WES and WGP [Member] | Senior Notes [Member]          
Derivative [Line Items]          
Debt instrument, principal amount     $ 2,000,000,000    
Debt instrument, stated interest rate     6.375%    
Debt instrument, maturity date     Sep. 15, 2017    
6.375% Senior Notes Due 2017 [Member] | Anadarko Excluding WES and WGP [Member] | Subsequent Event [Member] | Senior Notes [Member]          
Derivative [Line Items]          
Debt instrument, principal amount   $ 2,000,000,000      
Debt instrument, stated interest rate   6.375%      
Debt instrument, maturity date   Sep. 15, 2017      
Portion of 6.375% Senior Notes Due 2017 [Member] | Anadarko Excluding WES and WGP [Member] | Subsequent Event [Member] | Senior Notes [Member]          
Derivative [Line Items]          
Senior notes redeemed   $ 1,250,000,000      
Total Amount of Senior Notes Due in 2019 [Member] | Senior Notes [Member]          
Derivative [Line Items]          
Debt instrument, principal amount     $ 900,000,000    
Zero-Coupon Senior Notes [Member] | Anadarko Excluding WES and WGP [Member] | Senior Notes [Member]          
Derivative [Line Items]          
Debt instrument, maturity date     Oct. 10, 2036    
Debt Instrument, earliest call date     Oct. 10, 2016    
Zero-Coupon Senior Notes [Member] | Anadarko Excluding WES and WGP [Member] | Senior Notes [Member] | Accreted Value at Next Potential Put Date [Member]          
Derivative [Line Items]          
Debt instrument, accreted value     $ 839,000,000    
Not Designated as Hedging Instrument [Member]          
Derivative [Line Items]          
Gross derivative liabilities     1,758,000,000   1,722,000,000
Cash collateral held by counterparties     421,000,000   58,000,000
Aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed (net of collateral)     1,100,000,000   1,300,000,000
Not Designated as Hedging Instrument [Member] | Cash Collateral Posted Excluding Interest [Member]          
Derivative [Line Items]          
Cash collateral held by counterparties     420,000,000   58,000,000
Not Designated as Hedging Instrument [Member] | Permitted to Offset Gross Derivative Asset with Financial Institutions [Member]          
Derivative [Line Items]          
Gross derivative liabilities     238,000,000   347,000,000
Not Designated as Hedging Instrument [Member] | Interest-Rate Derivatives [Member]          
Derivative [Line Items]          
Gross derivative liabilities     1,640,000,000   1,542,000,000
Cash collateral held by counterparties     421,000,000   58,000,000
Not Designated as Hedging Instrument [Member] | Interest-Rate Derivatives [Member] | Other Liabilities [Member]          
Derivative [Line Items]          
Gross derivative liabilities     1,550,000,000   $ 1,488,000,000
Not Designated as Hedging Instrument [Member] | Interest-Rate Derivatives [Member] | Settled Interest Rate Swap [Member]          
Derivative [Line Items]          
Net cash paid in settlement of derivative instruments     193,000,000    
Not Designated as Hedging Instrument [Member] | Interest-Rate Derivatives [Member] | Interest Rate Swaps 1 Through 7 [Member]          
Derivative [Line Items]          
Notional principal amount of interest-rate swap     $ 1,700,000,000    
Not Designated as Hedging Instrument [Member] | Interest-Rate Derivatives [Member] | Interest Rate Swaps 3 and 5 [Member] | Modified Interest-Rate Swaps for Mandatory Termination Dates [Member]          
Derivative [Line Items]          
Mandatory termination date for interest-rate swap prior to modification     Sep. 15, 2021    
Notional principal amount of interest-rate swap     $ 500,000,000    
Natural Gas [Member] | Commodity [Member] | Not Designated as Hedging Instrument [Member]          
Derivative [Line Items]          
Financial derivative transactions | Mcf     4   8
[1] Excludes WES and WGP.
v3.4.0.3
Derivative Instruments - Interest-Rate Derivatives Table (Detail) - Not Designated as Hedging Instrument [Member] - Interest-Rate Derivatives [Member]
$ in Millions
 3 Months Ended
Mar. 31, 2016
USD ($)
Interest-Rate Swap 1 [Member]  
Derivative [Line Items]  
Notional principal amount of interest-rate swap $ 50
Reference period start date for interest-rate swap Sep. 15, 2016
Reference period end date for interest-rate swap Sep. 15, 2026
Mandatory termination date for interest-rate swap Sep. 15, 2016
Weighted-average interest rate for interest-rate swap 5.91%
Interest-Rate Swap 2 [Member]  
Derivative [Line Items]  
Notional principal amount of interest-rate swap $ 50
Reference period start date for interest-rate swap Sep. 15, 2016
Reference period end date for interest-rate swap Sep. 15, 2046
Mandatory termination date for interest-rate swap Sep. 15, 2016
Weighted-average interest rate for interest-rate swap 6.29%
Interest-Rate Swap 3 [Member]  
Derivative [Line Items]  
Notional principal amount of interest-rate swap $ 500
Reference period start date for interest-rate swap Sep. 15, 2016
Reference period end date for interest-rate swap Sep. 15, 2046
Mandatory termination date for interest-rate swap Sep. 15, 2018
Weighted-average interest rate for interest-rate swap 6.559%
Interest-Rate Swap 4 [Member]  
Derivative [Line Items]  
Notional principal amount of interest-rate swap $ 300
Reference period start date for interest-rate swap Sep. 15, 2016
Reference period end date for interest-rate swap Sep. 15, 2046
Mandatory termination date for interest-rate swap Sep. 15, 2020
Weighted-average interest rate for interest-rate swap 6.509%
Interest-Rate Swap 5 [Member]  
Derivative [Line Items]  
Notional principal amount of interest-rate swap $ 450
Reference period start date for interest-rate swap Sep. 15, 2017
Reference period end date for interest-rate swap Sep. 15, 2047
Mandatory termination date for interest-rate swap Sep. 15, 2018
Weighted-average interest rate for interest-rate swap 6.445%
Interest-Rate Swap 6 [Member]  
Derivative [Line Items]  
Notional principal amount of interest-rate swap $ 100
Reference period start date for interest-rate swap Sep. 15, 2017
Reference period end date for interest-rate swap Sep. 15, 2047
Mandatory termination date for interest-rate swap Sep. 15, 2020
Weighted-average interest rate for interest-rate swap 6.891%
Interest-Rate Swap 7 [Member]  
Derivative [Line Items]  
Notional principal amount of interest-rate swap $ 250
Reference period start date for interest-rate swap Sep. 15, 2017
Reference period end date for interest-rate swap Sep. 15, 2047
Mandatory termination date for interest-rate swap Sep. 15, 2021
Weighted-average interest rate for interest-rate swap 6.57%
v3.4.0.3
Derivative Instruments - Effect of Derivative Instruments - Balance Sheet Table (Detail) - Not Designated as Hedging Instrument [Member] - USD ($)
$ in Millions
Mar. 31, 2016
Dec. 31, 2015
Derivatives Fair Value [Line Items]    
Gross derivative assets $ 351 $ 526
Gross derivative liabilities (1,758) (1,722)
Commodity Derivatives [Member]    
Derivatives Fair Value [Line Items]    
Gross derivative assets 329 470
Gross derivative liabilities (118) (180)
Commodity Derivatives [Member] | Other Current Assets [Member]    
Derivatives Fair Value [Line Items]    
Gross derivative assets 322 462
Gross derivative liabilities (116) (177)
Commodity Derivatives [Member] | Other Assets [Member]    
Derivatives Fair Value [Line Items]    
Gross derivative assets 7 8
Gross derivative liabilities 0 0
Commodity Derivatives [Member] | Accrued Expenses [Member]    
Derivatives Fair Value [Line Items]    
Gross derivative assets 0 0
Gross derivative liabilities (2) (3)
Interest-Rate Derivatives [Member]    
Derivatives Fair Value [Line Items]    
Gross derivative assets 22 56
Gross derivative liabilities (1,640) (1,542)
Interest-Rate Derivatives [Member] | Other Current Assets [Member]    
Derivatives Fair Value [Line Items]    
Gross derivative assets 2 2
Gross derivative liabilities 0 0
Interest-Rate Derivatives [Member] | Other Assets [Member]    
Derivatives Fair Value [Line Items]    
Gross derivative assets 20 54
Gross derivative liabilities 0 0
Interest-Rate Derivatives [Member] | Accrued Expenses [Member]    
Derivatives Fair Value [Line Items]    
Gross derivative assets 0 0
Gross derivative liabilities (90) (54)
Interest-Rate Derivatives [Member] | Other Liabilities [Member]    
Derivatives Fair Value [Line Items]    
Gross derivative assets 0 0
Gross derivative liabilities $ (1,550) $ (1,488)
v3.4.0.3
Derivative Instruments - Effect of Derivative Instruments - Statement of Income Table (Detail) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Derivative [Line Items]    
Total (gains) losses on derivatives, net $ 299 $ 152
Commodity Derivatives [Member] | Gathering, Processing, and Marketing Sales [Member]    
Derivative [Line Items]    
Total (gains) losses on derivatives, net [1] 2 0
Commodity Derivatives [Member] | (Gains) Losses on Derivatives, Net [Member]    
Derivative [Line Items]    
Total (gains) losses on derivatives, net (28) (53)
Interest-Rate Derivatives [Member] | (Gains) Losses on Derivatives, Net [Member]    
Derivative [Line Items]    
Total (gains) losses on derivatives, net $ 325 $ 205
[1] Represents the effect of Marketing and Trading Derivative Activities.
v3.4.0.3
Derivative Instruments - Fair Value Table (Detail) - Not Designated as Hedging Instrument [Member] - USD ($)
$ in Millions
Mar. 31, 2016
Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Gross derivative assets $ 351 $ 526
Gross derivative liabilities (1,758) (1,722)
Derivative assets netting [1] (116) (178)
Derivative liabilities netting [1] 116 178
Cash collateral from counterparties (1) (8)
Cash collateral held by counterparties 421 58
Derivative assets 234 340
Derivative liabilities (1,221) (1,486)
Commodity Derivatives [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Gross derivative assets 329 470
Gross derivative liabilities (118) (180)
Derivative assets netting [1] (116) (178)
Derivative liabilities netting [1] 116 178
Cash collateral from counterparties (1) (8)
Cash collateral held by counterparties 0 0
Derivative assets 212 284
Derivative liabilities (2) (2)
Interest-Rate Derivatives [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Gross derivative assets 22 56
Gross derivative liabilities (1,640) (1,542)
Derivative assets netting [1] 0 0
Derivative liabilities netting [1] 0 0
Cash collateral from counterparties 0 0
Cash collateral held by counterparties 421 58
Derivative assets 22 56
Derivative liabilities (1,219) (1,484)
Recurring [Member] | Fair Value, Inputs, Level 1 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Gross derivative assets 1 10
Gross derivative liabilities 0 (1)
Recurring [Member] | Fair Value, Inputs, Level 2 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Gross derivative assets 350 516
Gross derivative liabilities (1,758) (1,721)
Recurring [Member] | Fair Value, Inputs, Level 3 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Gross derivative assets 0 0
Gross derivative liabilities 0 0
Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Gross derivative assets 1 10
Gross derivative liabilities 0 (1)
Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Gross derivative assets 328 460
Gross derivative liabilities (118) (179)
Recurring [Member] | Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Gross derivative assets 0 0
Gross derivative liabilities 0 0
Recurring [Member] | Interest-Rate Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Gross derivative assets 0 0
Gross derivative liabilities 0 0
Recurring [Member] | Interest-Rate Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Gross derivative assets 22 56
Gross derivative liabilities (1,640) (1,542)
Recurring [Member] | Interest-Rate Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Gross derivative assets 0 0
Gross derivative liabilities $ 0 $ 0
[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.
v3.4.0.3
Tangible Equity Units (Detail)
shares in Millions, $ in Millions
 3 Months Ended 6 Months Ended
Mar. 31, 2016
unit
$ / unit
Jun. 30, 2015
USD ($)
$ / unit
shares
Debt Component of 7.50% Tangible Equity Units [Member] | Senior Notes [Member]    
Tangible Equity Units [Line Items]    
Tangible equity unit rate 7.50%  
Principal amount per amortizing note 10.95  
Debt instrument, stated interest rate 1.50%  
Beginning date of quarterly cash installment payments Sep. 07, 2015  
Quarterly cash installment payment per amortizing note 0.9375  
First quarterly cash installment payment per amortizing note 0.9063  
Final Installment Payment Date Jun. 07, 2018  
7.50% Tangible Equity Units [Member]    
Tangible Equity Units [Line Items]    
Number of tangible equity units issued | shares   9.2
Tangible equity unit rate   7.50%
Stated amount per tangible equity unit   50.00
Total net proceeds | $   $ 445
Equity Component of 7.50% Tangible Equity Units [Member]    
Tangible Equity Units [Line Items]    
Purchase contract, mandatory settlement date Jun. 07, 2018  
Equity Component of 7.50% Tangible Equity Units [Member] | Settled In WGP Common Units [Member]    
Tangible Equity Units [Line Items]    
Maximum settlement rate | unit 0.8591  
Minimum settlement rate | unit 0.7159  
v3.4.0.3
Debt and Interest Expense - Debt Activity Table (Detail)
$ in Millions
 3 Months Ended
Mar. 31, 2016
USD ($)
Debt Instrument [Line Items]  
Balance at December 31, 2015 $ 15,648
Other, net 13
Balance at March 31, 2016 18,731
Western Gas Partners, LP [Member]  
Debt Instrument [Line Items]  
Balance at December 31, 2015 2,691
Other, net 0
Balance at March 31, 2016 3,021
Western Gas Equity Partners, LP excluding WES [Member]  
Debt Instrument [Line Items]  
Balance at December 31, 2015 0 [1]
Other, net 0
Balance at March 31, 2016 28 [1]
Anadarko Excluding WES and WGP [Member]  
Debt Instrument [Line Items]  
Balance at December 31, 2015 12,957 [2]
Other, net 13 [2]
Balance at March 31, 2016 15,682 [2]
Revolving Credit Facility [Member] | 364-Day Credit Facility due 2017 [Member]  
Debt Instrument [Line Items]  
Borrowings, credit facility 1,350
Repayments, credit facility (1,350)
Revolving Credit Facility [Member] | 364-Day Credit Facility due 2017 [Member] | Anadarko Excluding WES and WGP [Member]  
Debt Instrument [Line Items]  
Borrowings, credit facility 1,350 [2]
Repayments, credit facility (1,350) [2]
Revolving Credit Facility [Member] | WES RCF [Member]  
Debt Instrument [Line Items]  
Borrowings, credit facility 330
Revolving Credit Facility [Member] | WES RCF [Member] | Western Gas Partners, LP [Member]  
Debt Instrument [Line Items]  
Borrowings, credit facility 330
Revolving Credit Facility [Member] | WGP RCF [Member]  
Debt Instrument [Line Items]  
Borrowings, credit facility 28
Revolving Credit Facility [Member] | WGP RCF [Member] | Western Gas Equity Partners, LP excluding WES [Member]  
Debt Instrument [Line Items]  
Borrowings, credit facility 28 [1]
Commercial Paper [Member]  
Debt Instrument [Line Items]  
Repayments, commercial paper (250)
Commercial Paper [Member] | Anadarko Excluding WES and WGP [Member]  
Debt Instrument [Line Items]  
Repayments, commercial paper (250) [2]
Senior Notes [Member] | 7.50% Tangible Equity Units [Member]  
Debt Instrument [Line Items]  
Repayments, senior notes (8)
Senior Notes [Member] | Anadarko Excluding WES and WGP [Member] | 7.50% Tangible Equity Units [Member]  
Debt Instrument [Line Items]  
Repayments, senior notes (8) [2]
Senior Notes [Member] | 4.850% Senior Notes Due 2021 [Member]  
Debt Instrument [Line Items]  
Issuances $ 794
Debt instrument, stated interest rate 4.85%
Debt instrument, maturity date Mar. 15, 2021
Senior Notes [Member] | 4.850% Senior Notes Due 2021 [Member] | Anadarko Excluding WES and WGP [Member]  
Debt Instrument [Line Items]  
Issuances $ 794 [2]
Debt instrument, stated interest rate 4.85%
Debt instrument, maturity date Mar. 15, 2021
Senior Notes [Member] | 5.550% Senior Notes due 2026 [Member]  
Debt Instrument [Line Items]  
Issuances $ 1,088
Debt instrument, stated interest rate 5.55%
Debt instrument, maturity date Mar. 15, 2026
Senior Notes [Member] | 5.550% Senior Notes due 2026 [Member] | Anadarko Excluding WES and WGP [Member]  
Debt Instrument [Line Items]  
Issuances $ 1,088 [2]
Debt instrument, stated interest rate 5.55%
Debt instrument, maturity date Mar. 15, 2026
Senior Notes [Member] | 6.600% Senior Notes due 2046  
Debt Instrument [Line Items]  
Issuances $ 1,088
Debt instrument, stated interest rate 6.66%
Debt instrument, maturity date Mar. 15, 2046
Senior Notes [Member] | 6.600% Senior Notes due 2046 | Anadarko Excluding WES and WGP [Member]  
Debt Instrument [Line Items]  
Issuances $ 1,088 [2]
Debt instrument, stated interest rate 6.66%
Debt instrument, maturity date Mar. 15, 2046
[1] Excludes WES.
[2] Excludes WES and WGP.
v3.4.0.3
Debt and Interest Expense - Outstanding Debt Table (Detail) - USD ($)
$ in Millions
Mar. 31, 2016
Dec. 31, 2015
Debt Instrument [Line Items]    
Total borrowings at face value $ 20,411 $ 17,312
Net unamortized discounts, premiums, and debt issuance costs (3) [1] (1,680) (1,664)
Total borrowings 18,731 15,648
Capital lease obligation 20 20
Less short-term debt 3,025 32
Total long-term debt 15,726 15,636
Western Gas Partners, LP [Member]    
Debt Instrument [Line Items]    
Total borrowings at face value 3,050 2,720
Net unamortized discounts, premiums, and debt issuance costs (3) [1] (29) (29)
Total borrowings 3,021 2,691
Capital lease obligation 0 0
Less short-term debt 0 0
Total long-term debt 3,021 2,691
Western Gas Equity Partners, LP excluding WES [Member]    
Debt Instrument [Line Items]    
Total borrowings at face value [2] 28 0
Net unamortized discounts, premiums, and debt issuance costs (3) [1],[2] 0 0
Total borrowings [2] 28 0
Capital lease obligation [2] 0 0
Less short-term debt [2] 0 0
Total long-term debt [2] 28 0
Anadarko Excluding WES and WGP [Member]    
Debt Instrument [Line Items]    
Total borrowings at face value [3] 17,333 14,592
Net unamortized discounts, premiums, and debt issuance costs (3) [1],[3] (1,651) (1,635)
Total borrowings [3] 15,682 12,957
Capital lease obligation [3] 20 20
Less short-term debt [3] 3,025 32
Total long-term debt [3] $ 12,677 $ 12,945
[1] Unamortized discounts, premiums, and debt issuance costs are amortized over the term of the related debt. Debt issuance costs related to revolving credit facilities are included in other current assets and other assets on the Company’s Consolidated Balance Sheets.
[2] Excludes WES.
[3] Excludes WES and WGP.
v3.4.0.3
Debt and Interest Expense - Additional Information (Detail) - USD ($)
 3 Months Ended
Jan. 19, 2016
Mar. 31, 2016
Dec. 31, 2015
Debt Instrument [Line Items]      
Debt instrument, principal amount   $ 20,411,000,000 $ 17,312,000,000
Short-term debt   3,025,000,000 32,000,000
Anadarko Excluding WES and WGP [Member]      
Debt Instrument [Line Items]      
Debt instrument, principal amount [1]   17,333,000,000 14,592,000,000
Short-term debt [1]   3,025,000,000 32,000,000
Western Gas Partners, LP [Member]      
Debt Instrument [Line Items]      
Debt instrument, principal amount   3,050,000,000 2,720,000,000
Short-term debt   0 0
Western Gas Equity Partners, LP excluding WES [Member]      
Debt Instrument [Line Items]      
Debt instrument, principal amount [2]   28,000,000 0
Short-term debt [2]   0 0
Commercial Paper [Member] | Anadarko Excluding WES and WGP [Member]      
Debt Instrument [Line Items]      
Line of credit, maximum capacity   3,000,000,000  
Commercial paper, outstanding borrowings   $ 0  
Commercial Paper [Member] | Maximum [Member] | Anadarko Excluding WES and WGP [Member]      
Debt Instrument [Line Items]      
Debt instrument, term   397 days  
Fair Value, Inputs, Level 2 [Member] | Market Approach Valuation Technique [Member]      
Debt Instrument [Line Items]      
Estimated fair value of total borrowings   $ 18,900,000,000 $ 15,700,000,000
5.950% Senior Notes Due 2016 [Member] | Senior Notes [Member] | Anadarko Excluding WES and WGP [Member]      
Debt Instrument [Line Items]      
Short-term debt   $ 1,750,000,000  
Debt instrument, stated interest rate   5.95%  
Debt instrument, maturity date   Sep. 15, 2016  
Portion of 6.375% Senior Notes Due 2017 [Member] | Senior Notes [Member] | Anadarko Excluding WES and WGP [Member]      
Debt Instrument [Line Items]      
Short-term debt   $ 1,250,000,000  
6.375% Senior Notes Due 2017 [Member] | Senior Notes [Member] | Anadarko Excluding WES and WGP [Member]      
Debt Instrument [Line Items]      
Debt instrument, principal amount   $ 2,000,000,000  
Debt instrument, stated interest rate   6.375%  
Debt instrument, maturity date   Sep. 15, 2017  
Senior Notes 1 Through 3 [Member] | Senior Notes [Member] | Anadarko Excluding WES and WGP [Member]      
Debt Instrument [Line Items]      
Debt instrument, principal amount   $ 3,000,000,000  
Zero-Coupon Senior Notes [Member] | Senior Notes [Member] | Anadarko Excluding WES and WGP [Member]      
Debt Instrument [Line Items]      
Debt instrument, maturity date   Oct. 10, 2036  
Debt Instrument, earliest call date   Oct. 10, 2016  
Zero-Coupon Senior Notes [Member] | Senior Notes [Member] | Accreted Value at Next Potential Put Date [Member] | Anadarko Excluding WES and WGP [Member]      
Debt Instrument [Line Items]      
Debt instrument, accreted value   $ 839,000,000  
Five-Year Credit Facility [Member] | Revolving Credit Facility [Member] | Anadarko Excluding WES and WGP [Member]      
Debt Instrument [Line Items]      
Line of credit, maximum capacity   $ 3,000,000,000  
Debt instrument, term   5 years  
Line of credit, expiration date   Jan. 23, 2021  
Line of credit, outstanding borrowings   $ 0  
364-Day Credit Facility due 2016 [Member] | Revolving Credit Facility [Member] | Anadarko Excluding WES and WGP [Member]      
Debt Instrument [Line Items]      
Line of credit, maximum capacity $ 2,000,000,000    
Debt instrument, term 364 days    
364-Day Credit Facility due 2017 [Member] | Revolving Credit Facility [Member] | Anadarko Excluding WES and WGP [Member]      
Debt Instrument [Line Items]      
Line of credit, maximum capacity   $ 2,000,000,000  
Debt instrument, term   364 days  
Line of credit, expiration date   Jan. 15, 2017  
Line of credit, outstanding borrowings   $ 0  
WES RCF [Member] | Revolving Credit Facility [Member] | Western Gas Partners, LP [Member]      
Debt Instrument [Line Items]      
Line of credit, maximum capacity   $ 1,200,000,000  
Debt instrument, term   5 years  
Line of credit, expiration date   Feb. 26, 2019  
Line of credit, expandable maximum capacity   $ 1,500,000,000  
Line of credit, outstanding borrowings   $ 630,000,000  
Line of credit, interest rate   1.74%  
Letters of credit, outstanding   $ 5,000,000  
Line of credit, available borrowing capacity   565,000,000  
WGP RCF [Member] | Revolving Credit Facility [Member] | Western Gas Equity Partners, LP excluding WES [Member]      
Debt Instrument [Line Items]      
Line of credit, maximum capacity   $ 250,000,000  
Debt instrument, term   3 years  
Line of credit, expiration date   Mar. 14, 2019  
Line of credit, expandable maximum capacity   $ 500,000,000  
Line of credit, outstanding borrowings   $ 28,000,000  
Line of credit, interest rate   2.69%  
Line of credit, available borrowing capacity   $ 222,000,000  
WGP RCF [Member] | Revolving Credit Facility [Member] | Western Gas Equity Partners, LP excluding WES [Member] | Percentage Above Federal Funds Effective Rate [Member] | Alternate Base Rate [Member]      
Debt Instrument [Line Items]      
Applicable margin added   0.50%  
WGP RCF [Member] | Revolving Credit Facility [Member] | Western Gas Equity Partners, LP excluding WES [Member] | London Interbank Offered Rate (LIBOR) [Member]      
Debt Instrument [Line Items]      
Line of credit, variable rate floor   0.00%  
WGP RCF [Member] | Revolving Credit Facility [Member] | Western Gas Equity Partners, LP excluding WES [Member] | London Interbank Offered Rate (LIBOR) [Member] | Alternate Base Rate [Member]      
Debt Instrument [Line Items]      
Applicable margin added   1.00%  
WGP RCF [Member] | Revolving Credit Facility [Member] | Minimum [Member] | Western Gas Equity Partners, LP excluding WES [Member] | London Interbank Offered Rate (LIBOR) [Member]      
Debt Instrument [Line Items]      
Applicable margin added   2.00%  
WGP RCF [Member] | Revolving Credit Facility [Member] | Minimum [Member] | Western Gas Equity Partners, LP excluding WES [Member] | Base Rate [Member]      
Debt Instrument [Line Items]      
Applicable margin added   1.00%  
WGP RCF [Member] | Revolving Credit Facility [Member] | Maximum [Member] | Western Gas Equity Partners, LP excluding WES [Member] | London Interbank Offered Rate (LIBOR) [Member]      
Debt Instrument [Line Items]      
Applicable margin added   2.75%  
WGP RCF [Member] | Revolving Credit Facility [Member] | Maximum [Member] | Western Gas Equity Partners, LP excluding WES [Member] | Base Rate [Member]      
Debt Instrument [Line Items]      
Applicable margin added   1.75%  
[1] Excludes WES and WGP.
[2] Excludes WES.
v3.4.0.3
Debt and Interest Expense - Interest Expense Table (Detail) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Debt Disclosure [Abstract]    
Debt and other $ 258 $ 254
Capitalized interest (38) (38)
Total interest expense $ 220 $ 216
v3.4.0.3
Income Taxes - Income Tax Expense (Benefit) Table (Detail) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Income Tax Disclosure [Abstract]    
Income tax expense (benefit) $ (383) $ (1,392)
Income (loss) before income taxes $ (1,381) $ (4,628)
Effective tax rate 28.00% 30.00%
v3.4.0.3
Income Taxes - Additional Information (Detail) - USD ($)
$ in Billions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Income Tax Disclosure [Abstract]    
U.S. federal statutory rate 35.00% 35.00%
Accounts Receivable Other [Member]    
Income Tax Disclosure [Line Items]    
Income taxes receivable $ 1.1  
v3.4.0.3
Conveyance of Future Hard Minerals Royalty Revenues - Additional Information (Detail) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Deferred Revenue Disclosure [Abstract]    
Proceeds from conveyance of future hard minerals royalty revenues, net of transaction costs $ 413 $ 0
Maximum amount of total future royalty revenue third-party is entitled to 553  
Deferred Revenue Arrangement [Line Items]    
Amount of deferred revenue amortized in period $ 12  
Royalties Between $800 and $900 Million During the First 10 Years [Member]    
Deferred Revenue Arrangement [Line Items]    
Percentage of excess royalties 3.00%  
Baseline amount of excess royalties $ 800  
Royalties In Excess Of $900 Million During the First 10 Years [Member]    
Deferred Revenue Arrangement [Line Items]    
Percentage of excess royalties 4.00%  
Baseline amount of excess royalties $ 900  
Minimum [Member]    
Deferred Revenue Arrangement [Line Items]    
Term of conveyance 10 years  
Maximum [Member]    
Deferred Revenue Arrangement [Line Items]    
Term of conveyance 15 years  
v3.4.0.3
Conveyance of Future Hard Minerals Royalty Revenues - Schedule of Future Royalty Payments Table (Detail)
$ in Millions
Mar. 31, 2016
USD ($)
Deferred Revenue Disclosure [Abstract]  
2016 $ 25
2017 50
2018 50
2019 52
2020 56
Later years 320
Total $ 553
v3.4.0.3
Contingencies - Deepwater Horizon Events (Detail) - USD ($)
$ in Millions
 3 Months Ended 12 Months Ended
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2011
Macondo Exploration Well [Member]      
Loss Contingencies [Line Items]      
Nonoperated interest     25.00%
Deepwater Horizon [Member] | Judicial Ruling [Member] | Clean Water Act [Member]      
Loss Contingencies [Line Items]      
CWA penalty   $ 159.5  
Amount of penalty paid $ 159.5    
v3.4.0.3
Restructuring Charges Schedule of Resctucturing Charges Table (Detail) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Restructuring Cost and Reserve [Line Items]    
Total expected restructuring charges $ 389  
Restructuring charges 203 $ 0
General and Administrative Expense [Member]    
Restructuring Cost and Reserve [Line Items]    
Restructuring charges 203  
Cash Severance [Member]    
Restructuring Cost and Reserve [Line Items]    
Total expected restructuring charges 154  
Cash Severance [Member] | General and Administrative Expense [Member]    
Restructuring Cost and Reserve [Line Items]    
Restructuring charges 131  
Retirement Benefits [Member]    
Restructuring Cost and Reserve [Line Items]    
Total expected restructuring charges [1] 203  
Settlements 0  
Retirement Benefits [Member] | General and Administrative Expense [Member]    
Restructuring Cost and Reserve [Line Items]    
Restructuring charges [1] 49  
Share-based Compensation [Member]    
Restructuring Cost and Reserve [Line Items]    
Total expected restructuring charges 32  
Share-based Compensation [Member] | General and Administrative Expense [Member]    
Restructuring Cost and Reserve [Line Items]    
Restructuring charges 23  
Amount to be Recognized in 2017 [Member] | Retirement Benefits [Member]    
Restructuring Cost and Reserve [Line Items]    
Total expected restructuring charges $ 10  
[1] Includes termination benefits, curtailments, and settlements. There were no settlements recognized during the three months ended March 31, 2016. See Note 13—Pension Plans and Other Postretirement Benefits.
v3.4.0.3
Restructuring Charges Rollforward of Severance-related Liability Table (Detail) - Cash Severance [Member]
$ in Millions
 3 Months Ended
Mar. 31, 2016
USD ($)
Restructuring Cost and Reserve [Line Items]  
Accruals $ 131
Payments (79)
Accounts Payable [Member]  
Restructuring Cost and Reserve [Line Items]  
Balance at January 1 0
Balance at March 31 $ 52
v3.4.0.3
Pension Plans and Other Postretirement Benefits Components of Net Periodic Benefit Cost Table (Detail) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Pension Plan [Member]    
Components of net periodic benefit cost    
Service cost $ 26 $ 30
Interest cost 26 25
Expected return on plan assets (27) (27)
Amortization of net actuarial loss (gain) 8 13
Amortization of net prior service cost (credit) 0 0
Termination benefits expense 44 0
Curtailment expense 8 0
Net periodic benefit cost 85 41
Other Postretirement Benefit Plans, Defined Benefit [Member]    
Components of net periodic benefit cost    
Service cost 1 3
Interest cost 3 4
Expected return on plan assets 0 0
Amortization of net actuarial loss (gain) 0 0
Amortization of net prior service cost (credit) (6) 0
Termination benefits expense 0 0
Curtailment expense (3) 0
Net periodic benefit cost $ (5) $ 7
v3.4.0.3
Pension Plans and Other Postretirement Benefits Additional Information (Detail) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Defined Benefit Plan Disclosure [Line Items]    
Corresponding decrease in other comprehensive income related to the benefit obligation increase $ 166 $ 0
Pension Plan [Member]    
Defined Benefit Plan Disclosure [Line Items]    
Benefit obligation increase for the period 146  
Corresponding decrease in other comprehensive income related to the benefit obligation increase 146  
Other Postretirement Benefit Plans, Defined Benefit [Member]    
Defined Benefit Plan Disclosure [Line Items]    
Benefit obligation increase for the period 26  
Corresponding decrease in other comprehensive income related to the benefit obligation increase 26  
Unfunded Plans Defined Benefit [Member] | Pension Plan [Member] | Employee Severance [Member]    
Defined Benefit Plan Disclosure [Line Items]    
Expected future employer contributions in 2016 related to the workforce reduction program 82  
Expected future employer contributions in 2017 related to the workforce reduction program $ 23  
v3.4.0.3
Stockholders' Equity (Detail) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Net income (loss)    
Net income (loss) attributable to common stockholders $ (1,034) $ (3,268)
Income (loss) effect of TEUs 36 32
Less distributions on participating securities 0 1
Basic (1,035) (3,269)
Diluted $ (1,035) $ (3,269)
Shares    
Average number of common shares outstanding—basic 509 507
Average number of common shares outstanding—diluted 509 507
Excluded due to anti-dilutive effect 10 11
Net income (loss) per common share    
Basic $ (2.03) $ (6.45)
Diluted $ (2.03) $ (6.45)
7.50% Tangible Equity Units [Member] | Minimum Settlement Rate Effect On Noncontrolling Interest [Member]    
Net income (loss)    
Income (loss) effect of TEUs $ (1) $ 0
v3.4.0.3
Accumulated Other Comprehensive Income (Loss) (Detail)
$ in Millions
 3 Months Ended
Mar. 31, 2016
USD ($)
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]  
Balance $ 15,457
Other comprehensive income (loss), before reclassifications (105)
Reclassifications to Consolidated Statement of Income (3)
Balance 14,701
Interest-rate Derivatives Previously Subject to Hedge Accounting [Member]  
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]  
Balance (42)
Other comprehensive income (loss), before reclassifications 0
Reclassifications to Consolidated Statement of Income 2
Balance (40)
Pension and Other Postretirement Plans [Member]  
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]  
Balance (341)
Other comprehensive income (loss), before reclassifications (105)
Reclassifications to Consolidated Statement of Income (5)
Balance (451)
Accumulated Other Comprehensive Income (Loss) [Member]  
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]  
Balance (383)
Balance $ (491)
v3.4.0.3
Noncontrolling Interests (Detail) - USD ($)
shares in Thousands, $ in Millions
 1 Months Ended 3 Months Ended 12 Months Ended
Apr. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Western Gas Equity Partners, LP [Member] | Limited Partner [Member]      
Noncontrolling Interest [Line Items]      
Ownership interest in subsidiary   87.30%  
Public ownership interest in subsidiary   12.70%  
Western Gas Partners, LP [Member]      
Noncontrolling Interest [Line Items]      
Units issued in private placement   1,300  
Common units issued to the public     874
Net proceeds from common units     $ 57
Western Gas Partners, LP [Member] | Series A Preferred Units [Member]      
Noncontrolling Interest [Line Items]      
Units issued in private placement   14,000  
Net proceeds from Series A preferred units   $ 440  
Western Gas Partners, LP [Member] | Series A Preferred Units [Member] | Subsequent Event [Member]      
Noncontrolling Interest [Line Items]      
Units issued in private placement 8,000    
Net proceeds from Series A preferred units $ 248    
Western Gas Partners, LP [Member] | Class C Units [Member]      
Noncontrolling Interest [Line Items]      
Units issued in private placement   324 498
Western Gas Partners, LP [Member] | Limited Partner [Member]      
Noncontrolling Interest [Line Items]      
Public ownership interest in subsidiary   58.20%  
Western Gas Partners, LP [Member] | Limited Partner [Member] | Western Gas Equity Partners, LP, Ownership Interest [Member]      
Noncontrolling Interest [Line Items]      
Ownership interest in subsidiary   31.50%  
Western Gas Partners, LP [Member] | Limited Partner [Member] | Other Anadarko Subsidiaries, Ownership Interest [Member]      
Noncontrolling Interest [Line Items]      
Ownership interest in subsidiary   8.70%  
Western Gas Partners, LP [Member] | General Partner [Member] | Western Gas Equity Partners, LP, Ownership Interest [Member]      
Noncontrolling Interest [Line Items]      
Ownership interest in subsidiary   1.60%  
v3.4.0.3
Variable Interest Entities (Detail) - USD ($)
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Dec. 31, 2015
May. 31, 2008
Variable Interest Entity [Line Items]        
Interest Income for WES $ 258,000,000 $ 254,000,000    
Variable Interest Entity, Primary Beneficiary [Member] | Western Gas Partners, LP [Member]        
Variable Interest Entity [Line Items]        
Note receivable       $ 260,000,000
Debt instrument, term 30 years      
Fixed annual rate       6.50%
Interest Income for WES $ 4,000,000 4,000,000    
Deferred purchase price obligation - Anadarko 193,000,000   $ 189,000,000  
Above-market component of swap extensions with Anadarko $ 4,000,000 $ 0    
v3.4.0.3
Supplemental Cash Flow Information (Detail) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Cash (paid) received    
Interest, net of amounts capitalized (1) $ 299 $ 1,532 [1]
Income taxes, net of refunds (8) (5)
Non-cash investing activities    
Fair value of properties and equipment from non-cash transactions 0 54
Asset retirement cost additions 27 63
Accruals of property, plant, and equipment 623 1,080
Net liabilities assumed (divested) in acquisitions and divestitures 0 19
Non-cash investing and financing activities    
Floating production, storage, and offloading vessel construction period obligation $ 2 25
Tronox Litigation [Member] | Judicial Ruling [Member]    
Cash (paid) received    
Interest, net of amounts capitalized (1)   $ 1,200
[1] Includes $1.2 billion of interest related to the Tronox settlement payment in 2015.
v3.4.0.3
Segment Information - Additional Information (Detail)
 3 Months Ended
Mar. 31, 2016
Segment
Segment Reporting [Abstract]  
Number of reporting segments 3
Midstream Reporting Segment [Member]  
Segment Reporting Information [Line Items]  
Number of operating segments 2
v3.4.0.3
Segment Information - Reconciliation of Consolidated Adjusted EBITDAX to Income (Loss) Before Income Taxes Table (Detail) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Segment Reporting [Abstract]    
Income (loss) before income taxes $ (1,381) $ (4,628)
(Gains) losses on divestitures, net (2) 334
Exploration expense 126 1,083
DD&A 1,149 1,256
Impairments 16 2,783
Interest expense 220 216
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives 404 243
Restructuring charges 203 0
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]    
Net income (loss) attributable to noncontrolling interests 36 32
Consolidated Adjusted EBITDAX 700 1,286
Certain Other Nonoperating Items [Member]    
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]    
Certain other nonoperating items 0 22
Deepwater Horizon [Member] | Pending Litigation [Member]    
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]    
Other operating expense   4
Deepwater Horizon [Member] | Judicial Ruling [Member]    
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]    
Other operating expense 1  
Tronox Litigation [Member] | Judicial Ruling [Member]    
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]    
Other operating expense 0 5
Certain other nonoperating items $ 0 $ (5,210)
v3.4.0.3
Segment Information - Selected Financial Information for Anadarko's Reporting Segments Table (Detail) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Segment Reporting Information [Line Items]    
Revenues $ 1,634 $ 2,585
Other 38 70
Total revenues and other (1) 1,674 2,321
Operating costs and expenses (2) 2,538 6,529
Net cash from settlement of commodity derivatives (105) (91)
Other (income) expense, net 0 47
Net income (loss) attributable to noncontrolling interests 36 32
Total expenses and other 976 1,370
Consolidated Adjusted EBITDAX 700 1,286
(Gains) Losses on Derivatives, Net [Member] | Commodity Contract [Member]    
Segment Reporting Information [Line Items]    
Net cash from settlement of commodity derivatives (103) (90)
Gathering, Processing, and Marketing Sales [Member] | Commodity Contract [Member] | Not Designated as Hedging Instrument [Member]    
Segment Reporting Information [Line Items]    
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement 4 1
Excluding Gains Losses On Divestitures Net [Member]    
Segment Reporting Information [Line Items]    
Total revenues and other (1) [1] 1,672 2,655
Excluding Certain Items [Member]    
Segment Reporting Information [Line Items]    
Operating costs and expenses (2) [2] 1,043 1,403
Excluding Certain Other Nonoperating Items [Member]    
Segment Reporting Information [Line Items]    
Other (income) expense, net 0 25 [3]
Other and Intersegment Eliminations [Member]    
Segment Reporting Information [Line Items]    
Revenues 0 0
Other 38 70
Total expenses and other (192) (102)
Consolidated Adjusted EBITDAX (10) (56)
Other and Intersegment Eliminations [Member] | (Gains) Losses on Derivatives, Net [Member] | Commodity Contract [Member]    
Segment Reporting Information [Line Items]    
Net cash from settlement of commodity derivatives (103) (90)
Other and Intersegment Eliminations [Member] | Excluding Gains Losses On Divestitures Net [Member]    
Segment Reporting Information [Line Items]    
Total revenues and other (1) [1] (202) (158)
Other and Intersegment Eliminations [Member] | Excluding Certain Items [Member]    
Segment Reporting Information [Line Items]    
Operating costs and expenses (2) [2] (89) (37)
Other and Intersegment Eliminations [Member] | Excluding Certain Other Nonoperating Items [Member]    
Segment Reporting Information [Line Items]    
Other (income) expense, net 0 25 [3]
Other and Intersegment Eliminations [Member] | Intersegment Revenues [Member]    
Segment Reporting Information [Line Items]    
Revenues (240) (228)
Oil and Gas Exploration and Production Reporting Segment [Member]    
Segment Reporting Information [Line Items]    
Revenues 711 1,070
Oil and Gas Exploration and Production Reporting Segment [Member] | Intersegment Revenues [Member]    
Segment Reporting Information [Line Items]    
Revenues 601 1,117
Oil and Gas Exploration and Production Reporting Segment [Member] | Operating Segments [Member]    
Segment Reporting Information [Line Items]    
Total expenses and other 773 1,002
Consolidated Adjusted EBITDAX 539 1,185
Oil and Gas Exploration and Production Reporting Segment [Member] | Operating Segments [Member] | Excluding Gains Losses On Divestitures Net [Member]    
Segment Reporting Information [Line Items]    
Total revenues and other (1) [1] 1,312 2,187
Oil and Gas Exploration and Production Reporting Segment [Member] | Operating Segments [Member] | Excluding Certain Items [Member]    
Segment Reporting Information [Line Items]    
Operating costs and expenses (2) [2] 773 1,002
Midstream Reporting Segment [Member]    
Segment Reporting Information [Line Items]    
Revenues 125 174
Midstream Reporting Segment [Member] | Intersegment Revenues [Member]    
Segment Reporting Information [Line Items]    
Revenues 302 302
Midstream Reporting Segment [Member] | Operating Segments [Member]    
Segment Reporting Information [Line Items]    
Net income (loss) attributable to noncontrolling interests 36 32
Total expenses and other 219 272
Consolidated Adjusted EBITDAX 208 204
Midstream Reporting Segment [Member] | Operating Segments [Member] | Excluding Gains Losses On Divestitures Net [Member]    
Segment Reporting Information [Line Items]    
Total revenues and other (1) [1] 427 476
Midstream Reporting Segment [Member] | Operating Segments [Member] | Excluding Certain Items [Member]    
Segment Reporting Information [Line Items]    
Operating costs and expenses (2) [2] 183 240
Marketing Reporting Segment [Member]    
Segment Reporting Information [Line Items]    
Revenues 798 1,341
Marketing Reporting Segment [Member] | Intersegment Revenues [Member]    
Segment Reporting Information [Line Items]    
Revenues (663) (1,191)
Marketing Reporting Segment [Member] | Operating Segments [Member]    
Segment Reporting Information [Line Items]    
Total expenses and other 176 198
Consolidated Adjusted EBITDAX (37) (47)
Marketing Reporting Segment [Member] | Operating Segments [Member] | Gathering, Processing, and Marketing Sales [Member] | Commodity Contract [Member] | Not Designated as Hedging Instrument [Member]    
Segment Reporting Information [Line Items]    
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement 4 1
Marketing Reporting Segment [Member] | Operating Segments [Member] | Excluding Gains Losses On Divestitures Net [Member]    
Segment Reporting Information [Line Items]    
Total revenues and other (1) [1] 135 150
Marketing Reporting Segment [Member] | Operating Segments [Member] | Excluding Certain Items [Member]    
Segment Reporting Information [Line Items]    
Operating costs and expenses (2) [2] $ 176 $ 198
[1] Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.
[2] Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and other operating expense since these expenses are excluded from Adjusted EBITDAX.
[3] Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.
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