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Form 10-Q MARATHON OIL CORP For: Mar 31

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May 5, 2016 5:07 PM EDT


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 number 1-5153
Marathon Oil Corporation
(Exact name of registrant as specified in its charter)
Delaware
 
25-0996816
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
5555 San Felipe Street, Houston, TX  77056-2723
(Address of principal executive offices)

(713) 629-6600
(Registrant’s telephone number, including area code)
 
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 R No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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 R 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     þ  
Accelerated filer             o
Non-accelerated filer       o        (Do not check if a smaller reporting company) 
Smaller reporting company        o   
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).         
Yes o No þ
 
There were 847,648,273 shares of Marathon Oil Corporation common stock outstanding as of April 29, 2016.



MARATHON OIL CORPORATION
 
Unless the context otherwise indicates, references to “Marathon Oil,” “we,” “our,” or “us” in this Form 10-Q are references to Marathon Oil Corporation, including its wholly-owned and majority-owned subsidiaries, and its ownership interests in equity method investees (corporate entities, partnerships, limited liability companies and other ventures over which Marathon Oil exerts significant influence by virtue of its ownership interest).
For certain industry specific terms used in this Form 10-Q, please see "Definitions" in our 2015 Annual Report on Form 10-K.

 


1


Part I - Financial Information
Item 1. Financial Statements

MARATHON OIL CORPORATION
Consolidated Statements of Income (Unaudited)
 
Three Months Ended
 
March 31,
(In millions, except per share data)
2016
 
2015
Revenues and other income:
 
 
 
Sales and other operating revenues, including related party
$
714

 
$
1,280

Marketing revenues
58

 
204

Income from equity method investments
14

 
36

Net gain (loss) on disposal of assets
(60
)
 
1

Other income
4

 
11

Total revenues and other income
730

 
1,532

Costs and expenses:
 
 
 

Production
328

 
444

Marketing, including purchases from related parties
58

 
205

Other operating
109

 
107

Exploration
24

 
90

Depreciation, depletion and amortization
609

 
821

Impairments
1

 
—

Taxes other than income
48

 
67

General and administrative
151

 
171

Total costs and expenses
1,328

 
1,905

Income (loss) from operations
(598
)
 
(373
)
Net interest and other
(85
)
 
(47
)
Income (loss) before income taxes
(683
)
 
(420
)
Provision (benefit) for income taxes
(276
)
 
(144
)
Net income (loss)
$
(407
)
 
$
(276
)
Net income (loss) per share:
 

 
 

Basic
$
(0.56
)
 
$
(0.41
)
Diluted
$
(0.56
)
 
$
(0.41
)
Dividends per share
$
0.05

 
$
0.21

Weighted average common shares outstanding:
 

 
 

Basic
730

 
675

Diluted
730

 
675

 The accompanying notes are an integral part of these consolidated financial statements.

2


MARATHON OIL CORPORATION
Consolidated Statements of Comprehensive Income (Unaudited)
 
Three Months Ended
 
March 31,
(In millions)
2016
 
2015
Net income (loss)
$
(407
)
 
$
(276
)
Other comprehensive income (loss)
 

 
 

Postretirement and postemployment plans
 

 
 

Change in actuarial loss and other
(24
)
 
76

Income tax provision (benefit)
9

 
(27
)
Postretirement and postemployment plans, net of tax
(15
)
 
49

Comprehensive income (loss)
$
(422
)
 
$
(227
)
 The accompanying notes are an integral part of these consolidated financial statements.


3


MARATHON OIL CORPORATION
Consolidated Balance Sheets (Unaudited)
 
March 31,
 
December 31,
(In millions, except per share data)
2016
 
2015
Assets
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
2,072

 
$
1,221

Receivables, less reserve of $4 and $4
779

 
912

Inventories
306

 
313

Other current assets
111

 
144

Total current assets
3,268

 
2,590

Equity method investments
959

 
1,003

Property, plant and equipment, less accumulated depreciation,
 

 
 

depletion and amortization of $22,763 and $23,260
26,737

 
27,061

Goodwill
115

 
115

Other noncurrent assets
1,789

 
1,542

Total assets
$
32,868

 
$
32,311

Liabilities
 

 
 

Current liabilities:
 

 
 

Accounts payable
$
1,084

 
$
1,313

Payroll and benefits payable
79

 
133

Accrued taxes
151

 
132

Other current liabilities
211

 
150

Long-term debt due within one year
1

 
1

Total current liabilities
1,526

 
1,729

Long-term debt
7,280

 
7,276

Deferred tax liabilities
2,368

 
2,441

Defined benefit postretirement plan obligations
446

 
403

Asset retirement obligations
1,614

 
1,601

Deferred credits and other liabilities
283

 
308

Total liabilities
13,517

 
13,758

Commitments and contingencies


 


Stockholders’ Equity
 

 
 

Preferred stock – no shares issued or outstanding (no par value,
 
 
 
26 million shares authorized)
—

 
—

Common stock:
 

 
 

Issued – 937 million shares and 770 million shares (par value $1 per share,
 
 
 
1.1 billion shares authorized)
937

 
770

Securities exchangeable into common stock – no shares issued or
 

 
 

outstanding (no par value, 29 million shares authorized)
—

 
—

Held in treasury, at cost – 89 million and 93 million shares
(3,397
)
 
(3,554
)
Additional paid-in capital
7,428

 
6,498

Retained earnings
14,533

 
14,974

Accumulated other comprehensive loss
(150
)
 
(135
)
Total stockholders' equity
19,351

 
18,553

Total liabilities and stockholders' equity
$
32,868

 
$
32,311

 The accompanying notes are an integral part of these consolidated financial statements.

4


MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows (Unaudited)
 
Three Months Ended
 
March 31,
(In millions)
2016
 
2015
Increase (decrease) in cash and cash equivalents
 
 
 
Operating activities:
 

 
 

Net income (loss)
$
(407
)
 
$
(276
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 

 
 

Deferred income taxes
(320
)
 
(179
)
Depreciation, depletion and amortization
609

 
821

Impairments
1

 
—

Pension and other postretirement benefits, net
14

 
(7
)
Exploratory dry well costs and unproved property impairments
11

 
67

Net (gain) loss on disposal of assets
60

 
(1
)
Equity method investments, net
30

 
3

Changes in:
 
 
 

Current receivables
133

 
388

Inventories
7

 
(22
)
Current accounts payable and accrued liabilities
(121
)
 
(469
)
All other operating, net
57

 
(16
)
Net cash provided by operating activities
74

 
309

Investing activities:
 

 
 

Additions to property, plant and equipment
(454
)
 
(1,452
)
Disposal of assets
17

 
2

Investments - return of capital
14

 
10

All other investing, net
2

 
(2
)
Net cash used in investing activities
(421
)
 
(1,442
)
Financing activities:
 

 
 

Common stock issuance
1,232

 
—

Dividends paid
(34
)
 
(142
)
All other financing, net
—

 
4

Net cash provided by (used in) financing activities
1,198

 
(138
)
Effect of exchange rate on cash and cash equivalents
—

 
(1
)
Net increase (decrease) in cash and cash equivalents
851

 
(1,272
)
Cash and cash equivalents at beginning of period
1,221

 
2,398

Cash and cash equivalents at end of period
$
2,072

 
$
1,126

 The accompanying notes are an integral part of these consolidated financial statements.

5

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



1.    Basis of Presentation
These consolidated financial statements are unaudited; however, in the opinion of management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported.  All such adjustments are of a normal recurring nature unless disclosed otherwise.  These consolidated financial statements, including notes, have been prepared in accordance with the applicable rules of the SEC and do not include all of the information and disclosures required by U.S. GAAP for complete financial statements.
These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our 2015 Annual Report on Form 10-K.  The results of operations for the first quarter of 2016 are not necessarily indicative of the results to be expected for the full year.
2.   Accounting Standards
Not Yet Adopted
In March 2016, the FASB issued a new accounting standards update that changes several aspects of accounting for share-based payment transactions, including a requirement to recognize all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This standard is effective for us in the first quarter of 2017 and varying transition methods (modified retrospective, retrospective or prospective) should be applied to different provisions of the standard. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.
In February 2016, the FASB issued a new lease accounting standard, which requires lessees to recognize most leases, including operating leases, on the balance sheet as a right of use asset and lease liability. Short-term leases can continue being accounted for off balance sheet based on a policy election. This standard is effective for us in the first quarter of 2019 and should be applied using a modified retrospective approach at the beginning of the earliest period presented in the financial statements. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it may have on our consolidated results of operations, financial position or cash flows.
In January 2016, the FASB issued an accounting standards update that addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. This standard is effective for us in the first quarter of 2018. Early adoption is allowed for certain provisions. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In July 2015, the FASB issued an update that requires an entity to measure inventory at the lower of cost and net realizable value. This excludes inventory measured using LIFO or the retail inventory method. This standard is effective for us in the first quarter of 2017 and will be applied prospectively. Early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In August 2014, the FASB issued an update that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards.  This standard is effective for us for the annual period ending after December 15, 2016 and for annual periods and interim periods thereafter. Early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In May 2014, the FASB issued an update that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. Among other things, the standard requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for us in the first quarter of 2018 and should be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.
Recently Adopted
In May 2015, the FASB issued an update that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The amendment also

6

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


removes certain disclosure requirements regarding all investments that are eligible to be measured using the net asset value per share practical expedient and only requires certain disclosures on those investments for which an entity elects to use the net asset value per share expedient. This standard is effective for us in the first quarter of 2016 and was applied on a retrospective basis. This standard only modifies disclosure requirements; as such, there was no impact on our consolidated results of operations, financial position or cash flows.
In February 2015, the FASB issued an amendment to the guidance for determining whether an entity is a variable interest entity ("VIE"). The standard does not add or remove any of the five characteristics that determine whether an entity is a VIE. However, it does change the manner in which a reporting entity assesses one of the characteristics. In particular, when decision-making over the entity’s most significant activities has been outsourced, the standard changes how a reporting entity assesses if the equity holders at risk lack decision making rights. This standard is effective for us in the first quarter of 2016. The adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.
3.   Variable Interest Entity
The owners of the Athabasca Oil Sands Project, in which we hold a 20% undivided interest, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton, Alberta, Canada.  Costs under this contract are accrued and recorded on a monthly basis, with current liabilities of $2 million recorded at March 31, 2016 and December 31, 2015.  This contract qualifies as a variable interest contractual arrangement, and the Corridor Pipeline qualifies as a VIE.  We hold a variable interest but are not the primary beneficiary because our shipments are only 20% of the total; therefore, the Corridor Pipeline is not consolidated by us.  Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was $472 million as of March 31, 2016.  The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term.
4.
Income (Loss) per Common Share
Basic income (loss) per share is based on the weighted average number of common shares outstanding.  Diluted income per share assumes exercise of stock options, provided the effect is not antidilutive. The per share calculations below exclude 13 million stock options for the first three months of 2016 and 2015 that were antidilutive.
 
Three Months Ended March 31,
(In millions, except per share data)
2016
 
2015
Net income (loss)
$
(407
)
 
$
(276
)
 
 
 
 
Weighted average common shares outstanding
730

 
675

Weighted average common shares, diluted
730

 
675

Net income (loss) per share:
 
 
 
Basic
$
(0.56
)
 
$
(0.41
)
Diluted
$
(0.56
)
 
$
(0.41
)
5.
Dispositions
North America E&P Segment
In April 2016, we entered into agreements to sell our Wyoming upstream and midstream assets for proceeds of $870 million, before closing adjustments. The upstream properties are comprised mainly of waterflood developments in the Big Horn and Wind River basins. The midstream assets include the 570-mile Red Butte pipeline. We expect the transaction to close mid-year 2016.
In March and April 2016, we entered into separate agreements to sell our 10% working interest in the outside-operated Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Colorado, and certain undeveloped acreage in West Texas for a combined total of approximately $80 million, before closing adjustments. The transactions are expected to close mid-year 2016.
 
 

7

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


6.    Segment Information
  We have three reportable operating segments. Each of these segments is organized and managed based upon both geographic location and the nature of the products and services it offers.
•
N.A. E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in North America;
•
Int'l E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.; and
•
Oil Sands Mining (“OSM”) – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”).  Segment income represents income which excludes certain items not allocated to segments, net of income taxes, attributable to the operating segments. A portion of our corporate and operations support general and administrative costs are not allocated to the operating segments. These unallocated costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Gains or losses on dispositions, certain impairments, change in tax expense associated with a tax rate change, unrealized gains or losses on commodity derivative instruments, or other items that affect comparability (as determined by the CODM) also are not allocated to operating segments.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2016
 
 
 
Not Allocated
 
 
(In millions)
N.A. E&P
 
Int'l E&P
 
OSM
 
to Segments
 
Total
Sales and other operating revenues
$
493

 
$
96

 
$
148

 
$
(23
)
(c) 
$
714

Marketing revenues
31

 
15

 
12

 
—

 
58

Total revenues
524

 
111

 
160

 
(23
)
 
772

Income from equity method investments
—

 
14

 
—

 
—

 
14

Net gain (loss) on disposal of assets and other income
1

 
6

 
—

 
(63
)
(d) 
(56
)
Less:
 
 
 
 
 
 
 
 
 
Production expenses
134

 
53

 
141

 
—

 
328

Marketing costs
32

 
14

 
12

 
—

 
58

Exploration expenses
18

 
6

 
—

 
—


24

Depreciation, depletion and amortization
487

 
50

 
60

 
12

 
609

Impairments
1

 
—

 
—

 
—

 
1

Other expenses (a)
118

 
16

 
7

 
119

(e) 
260

Taxes other than income
42

 
—

 
5

 
1

 
48

Net interest and other
—

 
—

 
—

 
85

 
85

Income tax benefit
(112
)
 
(12
)
 
(17
)
 
(135
)
 
(276
)
Segment income (loss) / Net income (loss)
$
(195
)
 
$
4

 
$
(48
)
 
$
(168
)
 
$
(407
)
Capital expenditures (b)
$
315

 
$
32

 
$
9

 
$
3

 
$
359

(a) 
Includes other operating expenses and general and administrative expenses.
(b)Includes accruals.
(c) 
Unrealized loss on commodity derivative instruments.
(d) 
Related to the net loss on disposal of assets (see Note 5).
(e) 
Includes pension settlement loss of $48 million and severance related expenses associated with workforce reductions of $7 million (see Note 7).

8

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


 
Three Months Ended March 31, 2015
 
 
 
Not Allocated
 
 
(In millions)
N.A. E&P
 
Int'l E&P
 
OSM
 
to Segments
 
Total
Sales and other operating revenues
$
850

 
$
182

 
$
225

 
$
23

(c) 
$
1,280

Marketing revenues
178

 
26

 
—

 
—

 
204

Total revenues
1,028

 
208

 
225

 
23

 
1,484

Income from equity method investments
—

 
36

 
—

 
—

 
36

Net gain on disposal of assets and other income
—

 
10

 
1

 
1

 
12

Less:
 
 
 
 
 
 
 
 
 
Production expenses
202

 
67

 
175

 
—

 
444

Marketing costs
180

 
25

 
—

 
—

 
205

Exploration expenses
35

 
55

 
—

 
—

 
90

Depreciation, depletion and amortization
683

 
64

 
62

 
12

 
821

Other expenses (a)
117

 
23

 
9

 
129

(d) 
278

Taxes other than income
61

 
—

 
5

 
1

 
67

Net interest and other
—

 
—

 
—

 
47

 
47

Income tax benefit
(89
)
 
(3
)
 
(6
)
 
(46
)
 
(144
)
Segment income (loss) / Net income (loss)
$
(161
)
 
$
23

 
$
(19
)
 
$
(119
)
 
$
(276
)
Capital expenditures (b)
$
933

 
$
146

 
$
21

 
$
2

 
$
1,102

(a) 
Includes other operating expenses and general and administrative expenses.
(b) 
Includes accruals.
(c) 
Unrealized gain on commodity derivative instruments.
(d) 
Includes $43 million of severance related expenses associated with a workforce reduction and pension settlement loss of $17 million (see Note 7).

7.    Defined Benefit Postretirement Plans
The following summarizes the components of net periodic benefit cost:
 
 
 
 
 
 
 
 
 
Three Months Ended March 31,
  
Pension Benefits
 
Other Benefits
(In millions)
2016
 
2015
 
2016
 
2015
Service cost
$
6

 
$
12

 
$
1

 
$
1

Interest cost
11

 
14

 
3

 
3

Expected return on plan assets
(15
)
 
(19
)
 
—

 
—

Amortization:
 
 
 

 
 

 
 

– prior service cost (credit)
(2
)
 
1

 
(1
)
 
(1
)
– actuarial loss
3

 
7

 
—

 
—

Net settlement loss(a)
48

 
17

 
—

 
—

Net curtailment loss (gain) (b)
—

 
1

 
—

 
(6
)
Net periodic benefit cost
$
51


$
33


$
3


$
(3
)
(a) 
Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan's total service and interest cost for that year.
(b) 
Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans.
During the first three months of 2016, we recorded the effects of settlements of our U.S. pension plans. As required, we remeasured the plans' assets and liabilities as of the applicable balance sheet dates. The cumulative effects of these events are included in the remeasurement and reflected in both the pension liability and net periodic benefit cost.
During the first three months of 2016, we made contributions of $14 million to our funded pension plans.  We expect to make additional contributions up to an estimated $48 million to our funded pension plans over the remainder of 2016.  During the first three months of 2016, we made payments of $19 million and $5 million related to unfunded pension plans and other postretirement benefit plans, respectively.

9

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


8.    Income Taxes
Effective Tax Rate
The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The difference between the total provision and the sum of the amounts allocated to segments is reported in the “Not Allocated to Segments” column of the tables in Note 6.
Our effective income tax rates for the first three months of 2016 and 2015 were 40% and 34%.  In Libya, uncertainty remains around the timing of future production and sales levels. Reliable estimates of 2016 and 2015 Libyan annual ordinary income from our operations could not be made and the range of possible scenarios in the worldwide annual effective tax rate calculation demonstrates significant variability. Thus, the tax benefit applicable to Libyan ordinary loss was recorded as a discrete item in the first three months of 2016 and 2015.  For the first three months of 2016 and 2015, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss). Excluding Libya, the effective tax rates, would be 39% and 31% for the first three months of 2016 and 2015. The change was driven by a shift in jurisdictional income.
Deferred Tax Assets
In connection with our assessment of the realizability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of our deferred tax assets will not be realized.  In the event it is more likely than not that some portion or all of our deferred taxes will not be realized, such assets are reduced by a valuation allowance. Future increases to our valuation allowance are possible if our estimates and assumptions (particularly as they relate to downward revisions of our long-term commodity price forecast) are revised such that they reduce estimates of future taxable income during the carryforward period.
9.   Inventories
 Liquid hydrocarbons, natural gas and bitumen are recorded at weighted average cost and carried at the lower of cost or market value. Supplies and other items consist principally of tubular goods and equipment which are valued at weighted average cost and reviewed periodically for obsolescence or impairment when market conditions indicate.
 
March 31,
 
December 31,
(In millions)
2016
 
2015
Liquid hydrocarbons, natural gas and bitumen
$
33

 
$
35

Supplies and other items
273

 
278

Inventories, at cost
$
306

 
$
313

10.  Property, Plant and Equipment, net of Accumulated Depreciation, Depletion and Amortization
 
March 31,
 
December 31,
(In millions)
2016
 
2015
North America E&P
$
14,953

 
$
15,226

International E&P
2,521

 
2,533

Oil Sands Mining
9,148

 
9,197

Corporate
115

 
105

Net property, plant and equipment
$
26,737


$
27,061

Our Libya operations continue to be impacted by civil unrest. Operations were interrupted in mid-2013 as a result of the shutdown of the Es Sider crude oil terminal, and although temporarily re-opened during the second half of 2014, production remains shut-in. Considerable uncertainty remains around the timing of future production and sales levels.
As of March 31, 2016, our net property, plant and equipment investment in Libya is $776 million, and total proved reserves (unaudited) in Libya as of December 31, 2015 are 235 million barrels of oil equivalent ("mmboe"). We and our partners in the Waha concessions continue to assess the situation and the condition of our assets in Libya. Our periodic assessment of the carrying value of our net property, plant and equipment in Libya specifically considers the net investment in the assets, the duration of our concessions and the reserves anticipated to be recoverable in future periods. The undiscounted cash flows related to our Libya assets continue to exceed the carrying value of $776 million by a material amount.

10

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Exploratory well costs capitalized greater than one year after completion of drilling were $120 million and $85 million as of March 31, 2016 and December 31, 2015. The $35 million increase primarily relates to the Alba Block Sub Area B offshore Equatorial Guinea where the Rodo well reached total depth in the first quarter of 2015. We have since completed a seismic feasibility study and continue to finalize next steps in the Alba Block Sub Area B exploration program.
11.  Fair Value Measurements
 Fair Values - Recurring
The following tables present assets and liabilities accounted for at fair value on a recurring basis as of March 31, 2016 and December 31, 2015 by fair value hierarchy level.
 
March 31, 2016
(In millions)
Level 1
 
Level 2
 
Level 3
 
Total
Derivative instruments, assets
 
 
 
 
 
 
 
     Commodity (a)
$
—

 
$
51

 
$
—

 
$
51

     Interest rate
—

 
12

 
—

 
12

Derivative instruments, assets
$
—

 
$
63

 
$
—

 
$
63

Derivative instruments, liabilities
 
 
 
 
 
 
 
     Commodity (a)
$
—

 
$
24

 
$
—

 
$
24

Derivative instruments, liabilities
$
—

 
$
24

 
$
—

 
$
24

(a)  
Derivative instruments are recorded on a net basis in the company's balance sheet (see Note 12).
 
December 31, 2015
(In millions)
Level 1
 
Level 2
 
Level 3
 
Total
Derivative instruments, assets
 
 
 
 
 
 
 
     Commodity (a)
$
—

 
$
51

 
$
—

 
$
51

Interest rate
$
—

 
$
8

 
$
—

 
$
8

Derivative instruments, assets
$
—

 
$
59

 
$
—

 
$
59

Derivative instruments, liabilities
 
 
 
 
 
 
 
     Commodity (a)
$
—

 
$
1

 
$
—

 
$
1

Derivative instruments, liabilities
$
—

 
$
1

 
$
—

 
$
1

(a)  
Derivative instruments are recorded on a net basis in the company's balance sheet (see Note 12).
Commodity derivatives include three-way collars, extendable three-way collars, call options, swaps and swaptions. These instruments are measured at fair value using either the Black-Scholes Model or the Black Model. Inputs to both models include prices, interest rates, and implied volatility. The inputs to these models are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.
Interest rate swaps are measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs. See Note 12 for additional discussion of the types of derivative instruments we use.
Fair Values – Goodwill
Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. We estimate the fair value of our International E&P reporting unit using a combination of market and income approaches. The market approach referenced observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value, and valuation multiples of us and our peers for the investor analyst community. The income approach utilized discounted cash flows, which were based on forecasted assumptions. Key assumptions to the income approach include future liquid hydrocarbon and natural gas pricing, estimated quantities of liquid hydrocarbons and natural gas proved and probable reserves, estimated timing of production, discount rates, future capital requirements and operating expenses and tax rates. The assumptions used in the income approach are consistent with those that management uses to make business decisions. These valuations methodologies represent Level 3 fair value measurements. A triggering event related to price declines in our common stock required us to reassess our goodwill

11

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


for impairment as of March 31, 2016. Based on the results of this assessment, we concluded no impairment was required. While the fair value of our International E&P reporting unit exceeded book value, subsequent commodity price and/or common stock declines may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.
Fair Values – Financial Instruments
Our current assets and liabilities include financial instruments, the most significant of which are receivables, long-term debt and payables. We believe the carrying values of our receivables and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our credit rating, and (3) our historical incurrence of and expected future insignificant bad debt expense, which includes an evaluation of counterparty credit risk.
The following table summarizes financial instruments, excluding receivables, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at March 31, 2016 and December 31, 2015.
 
March 31, 2016
 
December 31, 2015
 
Fair
 
Carrying
 
Fair
 
Carrying
(In millions)
Value
 
Amount
 
Value
 
Amount
Financial assets
 
 
 
 
 
 
 
Other noncurrent assets
$
115

 
$
120

 
$
104

 
$
118

Total financial assets  
$
115

 
$
120

 
$
104

 
$
118

Financial liabilities
 

 
 

 
 

 
 

     Other current liabilities
$
34

 
$
33

 
$
34

 
$
33

     Long-term debt, including current portion (a)
6,575

 
7,291

 
6,723

 
7,291

Deferred credits and other liabilities
104

 
105

 
97

 
95

Total financial liabilities  
$
6,713

 
$
7,429

 
$
6,854

 
$
7,419

(a)    Excludes capital leases, debt issuance costs and interest rate swap adjustments.
Fair values of our financial assets included in other noncurrent assets, and of our financial liabilities included in other current liabilities and deferred credits and other liabilities, are measured using an income approach and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value.
Most of our long-term debt instruments are publicly-traded. A market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is used to measure the fair value of such debt. The fair value of our debt that is not publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.
12. Derivatives
For further information regarding the fair value measurement of derivative instruments, see Note 11. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts where they appear on the consolidated balance sheets.

12

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


 
March 31, 2016
 
 
(In millions)
Asset
 
Liability
 
Net Asset
 
Balance Sheet Location
Fair Value Hedges
 
 
 
 
 
 
 
     Interest rate
$
12

 
$
—

 
$
12

 
Other noncurrent assets
Total Designated Hedges
$
12

 
$
—

 
$
12

 
 
 
 
 
 
 
 
 
 
Not Designated as Hedges
 
 
 
 
 
 
 
     Commodity
$
51

 
$
7

 
$
44

 
Other current assets
Total Not Designated as Hedges
$
51

 
$
7

 
$
44

 
 
     Total
$
63


$
7


$
56

 
 
 
 
 
 
 
 
 
 
 
March 31, 2016
 
 
(In millions)
Asset
 
Liability
 
Net Liability
 
Balance Sheet Location
Not Designated as Hedges
 
 
 
 
 
 
 
     Commodity
$
—

 
$
17

 
$
17

 
Deferred credits and other liabilities
Total Not Designated as Hedges
$
—

 
$
17

 
$
17

 
 
     Total
$
—

 
$
17

 
$
17

 
 
 
 
 
 
 
 
 
 
 
December 31, 2015
 
 
(In millions)
Asset
 
Liability
 
Net Asset
 
Balance Sheet Location
Fair Value Hedges
 
 
 
 
 
 
 
     Interest rate
$
8

 
$
—

 
$
8

 
Other noncurrent assets
Total Designated Hedges
$
8

 
$
—

 
$
8

 
 
 
 
 
 
 
 
 
 
Not Designated as Hedges
 
 
 
 
 
 
 
     Commodity
$
51

 
$
1

 
$
50

 
Other current assets
Total Not Designated as Hedges
$
51

 
$
1

 
$
50

 
 
     Total
$
59

 
$
1

 
$
58

 
 
Derivatives Designated as Fair Value Hedges
The following table presents, by maturity date, information about our interest rate swap agreements, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.
 
March 31, 2016
 
December 31, 2015
 
Aggregate Notional Amount
Weighted Average, LIBOR-Based,
 
Aggregate Notional Amount
Weighted Average, LIBOR-Based,
Maturity Dates
(in millions)
Floating Rate
 
(in millions)
Floating Rate
October 1, 2017
$
600

4.92
%
 
$
600

4.73
%
March 15, 2018
$
300

4.77
%
 
$
300

4.66
%

13

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


The pretax effects of derivative instruments designated as hedges of fair value in our consolidated statements of income are summarized in the table below. There is no ineffectiveness related to fair value hedges.
 
 
Gain (Loss)
 
 
 
Three Months Ended March 31,
(In millions)
Income Statement Location
 
2016
 
2015
Derivative
 
 
 
 
 
Interest rate
Net interest and other
 
$
4

 
$
5

Hedged Item
 
 
 

 
 

Long-term debt
Net interest and other
 
$
(4
)
 
$
(5
)
 Derivatives not Designated as Hedges
During 2015 and the first quarter of 2016, we entered into multiple crude oil and natural gas derivatives indexed to NYMEX WTI and Henry Hub related to a portion of our forecasted North America E&P sales through December 2017. These commodity derivatives consist of three-way collars, extendable three-way collars, call options, swaps, and swaptions. Three-way collars consist of a sold call (ceiling), a purchased put (floor) and a sold put. The ceiling price is the maximum we will receive for the contract volumes, the floor is the minimum price we will receive, unless the market price falls below the sold put strike price. In this case, we receive the NYMEX WTI/Henry Hub price plus the difference between the floor and the sold put price. These commodity derivatives were not designated as hedges. The following table sets forth outstanding derivative contracts as of March 31, 2016 and the weighted average prices for those contracts:
Crude Oil (a)
 
2016
Year Ending December 31,
 
Second Quarter
Third Quarter
Fourth Quarter
2017
Three-Way Collars (b)
Volume (Bbls/day)
39,000
37,000
37,000
—
Price per Bbl:
 
 
 
 
Ceiling
$55.47
$54.52
$54.52
—
Floor
$51.56
$50.83
$50.83
—
Sold put
$41.67
$41.22
$41.22
—
Options (c)
 
 
 
 
Volume (Bbls/day)
10,000
10,000
10,000
25,000
Price per Bbl
$72.39
$72.39
$72.39
$60.67
Swaps
 
 
 
 
Volume (Bbls/day)
25,000
—
—
—
Price per Bbl
$39.25
—
—
—
(a) Subsequent to March 31, 2016, we entered into 10,000 Bbls/day of two-way collars for July - December 2016 with a ceiling price of $50.00 and a floor price of $41.55. We also entered into 10,000 Bbls/day of 2016 three-way collars for May - December 2016 with a ceiling price of $58.51, a floor price of $48.00, and a sold put price of $40.00, traded in conjunction with sold call options of 10,000 Bbls/day for 2017 at $65.00.
(b) 
A counterparty has the option, exercisable on June 30, 2016, to extend three-way collars for 2,000 Bbls/day through the remainder of 2016 at a ceiling of $73.13, floor of $65.00 and sold put of $50.00.
(c) 
Call options settle monthly.

14

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Natural Gas (a)
 
2016
Year Ending December 31,
 
Second Quarter
Third Quarter
Fourth Quarter
2017
Three-Way Collars (b)
 
 
 
 
Volume (MMBtu/day)
20,000
20,000
20,000
20,000
Price per MMBtu
 
 
 
 
Ceiling
$2.93
$2.93
$2.93
$3.07
Floor
$2.50
$2.50
$2.50
$2.75
Sold put
$2.00
$2.00
$2.00
$2.25
(a) 
Subsequent to March 31, 2016, we entered into 20,000 MMBtu/day of 2017 three-way collars with a ceiling price of $3.50, a floor price of $2.75, and a sold put price of $2.25.
(b) 
Counterparty has the option to execute fixed-price swaps (swaptions) at a weighted average price of $2.93 per MMBtu indexed to NYMEX Henry Hub, which is exercisable on December 22, 2016. If counterparty exercises, the term of the fixed-price swaps would be for the calendar year 2017 and, if all such options are exercised, 20,000 MMBtu per day.
The impact of these commodity derivative instruments appears in sales and other operating revenues in our consolidated statements of income and was a net loss of $2 million and net gain of $26 million in the first quarters of 2016 and 2015, respectively.
13.    Incentive Based Compensation
 Stock options, restricted stock awards and restricted stock units
The following table presents a summary of activity for the first three months of 2016: 
 
Stock Options
 
Restricted Stock Awards & Units
 
Number of
Shares
 
Weighted
Average
Exercise Price
 
Awards
 
Weighted
Average Grant
Date Fair Value
Outstanding at December 31, 2015
12,665,419

 

$29.97

 
4,017,344

 

$30.76

Granted
1,680,000

(a) 

$7.22

 
5,230,708

 

$7.91

Options Exercised/Stock Vested
—

 
—

 
(44,096
)
 

$32.01

Canceled
(181,681
)
 

$29.69

 
(220,614
)
 

$30.00

Outstanding at March 31, 2016
14,163,738

 

$27.27

 
8,983,342

 

$17.47

(a)    The weighted average grant date fair value of stock option awards granted was $1.97 per share.
Stock-based performance unit awards
 During the first three months of 2016, we granted 1,205,517 stock-based performance units to certain officers. The grant date fair value per unit was $3.72.
14.  Debt
Revolving Credit Facility
As of March 31, 2016, we had no borrowings against our revolving credit facility (the "Credit Facility"), as described below.
In March 2016, we increased our $3.0 billion unsecured Credit Facility by $300 million to a total of $3.3 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the increase.
The Credit Facility includes a covenant requiring that our ratio of total debt to total capitalization not exceed 65% as of the last day of each fiscal quarter. If an event of default occurs, the lenders holding more than half of the commitments may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and

15

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


the cash collateralization of all outstanding letters of credit under the Credit Facility. As of March 31, 2016, we were in compliance with this covenant with a debt-to-capitalization ratio of 27%.
15.  Reclassifications Out of Accumulated Other Comprehensive Loss
The following table presents a summary of amounts reclassified from accumulated other comprehensive loss:
 
Three Months Ended March 31,
 
 
(In millions)
2016
 
2015
 
Income Statement Line
 
 
 
 
Postretirement and postemployment plans
 
 
 
 
 
Amortization of actuarial loss
$
(3
)
 
$
(7
)
 
General and administrative
Net settlement loss
(48
)
 
(17
)
 
General and administrative
Net curtailment gain (loss)
—

 
5

 
General and administrative
 
(51
)
 
(19
)
 
Income (loss) from operations
 
19

 
7

 
Provision (benefit) for income taxes
Total reclassifications to expense
$
(32
)
 
$
(12
)
 
Net income (loss)

16. Stockholder's Equity
In March 2016, we issued 166,750,000 shares of our common stock, par value $1 per share, at a price of $7.65 per share, excluding underwriting discounts and commissions, for net proceeds of $1,232 million. The proceeds will be used to strengthen our balance sheet and for general corporate purposes, including funding a portion of our Capital Program.

17.  Supplemental Cash Flow Information
 
Three Months Ended March 31,
(In millions)
2016
 
2015
Net cash (used in) operating activities:
 
 
 
Interest paid (net of amounts capitalized)
$
(87
)
 
$
(55
)
Income taxes paid to taxing authorities
(15
)
 
(47
)
Noncash investing activities:
 

 
 

Asset retirement cost increase
$
2

 
$
21

Asset retirement obligations assumed by buyer
54

 
—

18.   Commitments and Contingencies
  We are a defendant in a number of legal and administrative proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims, tax disputes and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.  
19.   Subsequent Event
In September 2015, we announced our intention to scale back our conventional exploration program, with future exploration investment focused on fulfilling our existing commitments in the Gulf of Mexico and Gabon. In April 2016, we made the decision not to drill any of our remaining Gulf of Mexico undeveloped leases. As a result, we expect to record a non-cash impairment between $140 million and $150 million in the second quarter of 2016. We retain our existing deepwater drilling rig commitment, in which we have approximately 200 days of contract term remaining.

16



Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the preceding consolidated financial statements and notes in Item 1.
Executive Overview
We are an independent global exploration and production company based in Houston, Texas with operations in North America, Europe and Africa and a focus on U.S. unconventional resource plays. Total proved reserves were 2.2 billion boe at December 31, 2015 and total assets were $33 billion at March 31, 2016.
Our significant strategic actions and financial results include the following:
•
Continued to strengthen the balance sheet
◦
Raised net $1.2 billion from equity offering in the first quarter of 2016
◦
At the end of the first quarter of 2016, we had $5.4 billion of liquidity, comprised of $2.1 billion in cash and an undrawn $3.3 billion revolving credit facility
◦
Announced or closed $1.3 billion of non-core asset sales since August 2015, surpassing our target of $750 million to $1 billion. The largest component of this total was the $950 million non-core asset sales announced in April 2016 which consisted of:
▪
Wyoming upstream and midstream assets of $870 million, before closing adjustments
▪
Shenandoah discovery in the Gulf of Mexico (10% outside operated working interest); Piceance operated natural gas assets in Colorado; certain undeveloped acreage in West Texas for a combined total of approximately $80 million, before closing adjustments
◦
Additions to property, plant and equipment, including accruals, of $359 million for the first quarter of 2016, down 67% compared to the year-ago quarter, reflecting continued capital discipline
◦
Executed additional commodity derivative instruments during the first quarter to reduce commodity price uncertainty for North America E&P crude oil and natural gas
◦
Reduced production expenses per boe in the first quarter of 2016 compared to the same period last year
▪
North America E&P - 22% reduction to $6.17 per boe
▪
Oil Sands Mining - 17% reduction to $28.80 per boe
◦
Cash-adjusted debt-to-capital ratio of 21% at March 31, 2016, as compared with 25% at December 31, 2015
•
Financial results
◦
Net loss per share of $0.56 in the first quarter of 2016 as compared to net loss per share of $0.41 in the same period last year
Outlook
Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows and the amount of capital available to reinvest into our business. We remain on track to achieve our objective of spending within our cash flows in 2016, inclusive of the non-core asset sales recently announced. We will continue to strengthen the balance sheet, evaluate our portfolio for strategic opportunities, adjust our Capital Program as necessary, and drive the fundamentals of expense management.

17

Exploration Update
In September 2015, we announced our intention to scale back our conventional exploration program, with future exploration investment focused on fulfilling our existing commitments in the Gulf of Mexico and Gabon.  In April 2016, we made the decision not to drill any of our remaining Gulf of Mexico undeveloped leases. As a result, we expect to record a non-cash impairment between $140 million and $150 million in the second quarter of 2016. We retain our existing deepwater drilling rig commitment, in which we have approximately 200 days of contract term remaining. We are currently evaluating our options related to this commitment. We expect this rig to return to us late in the third quarter or early fourth quarter of 2016. 
Operations
The following table presents a summary of our sales volumes for each of our segments. Refer to the Results of Operations for a price-volume analysis for each of the segments.
 
Three Months Ended March 31,
Net Sales Volumes
2016
 
2015
 
Increase
(Decrease)
North America E&P (mboed)
239
 
283
 
(16)%
International E&P (mboed)
96
 
116
 
(17)%
Oil Sands Mining (mbbld) (a)
59
 
60
 
(2)%
Total (mboed)
394
 
459
 
(14)%
(a) Includes blendstocks
North America E&P
Net sales volumes in the segment were lower in the first quarter of 2016 primarily as a result of decreased drilling and completion activity resulting in fewer wells brought to sales as well as 2015 dispositions of certain non-core assets (Gulf of Mexico and East Texas, North Louisiana and Wilburton, Oklahoma). The following tables provide details regarding net sales volumes, sales mix and operational drilling activity for our significant operations within this segment:
 
Three Months Ended March 31,
Net Sales Volumes
2016
 
2015
 
Increase
(Decrease)
Equivalent Barrels (mboed)
 
 
 
 
 
Eagle Ford
121
 
147
 
(18)%
Oklahoma Resource Basins
27
 
25
 
8%
Bakken
57
 
57
 
—
Other North America (a)
34
 
54
 
(37)%
Total North America E&P
239
 
283
 
(16)%
(a)     Includes Gulf of Mexico and other conventional onshore U.S. production, which was impacted by the sale of certain Gulf of Mexico assets in the fourth quarter of 2015.
 
Three Months Ended March 31, 2016
Sales Mix - U.S. Resource Plays
Crude oil and condensate
 
Natural gas liquids
 
Natural gas
 
 
 
 
 
 
Eagle Ford
58%
 
21%
 
21%
Oklahoma Resource Basins
19%
 
26%
 
55%
Bakken
82%
 
11%
 
7%
 
 
 
 
 
 
 
 
 
 
 
 


 
Three Months Ended March 31,
 
2016
 
2015
Gross Operated
 
 
 
Eagle Ford:
 
 
 
Wells drilled to total depth
58
 
88
Wells brought to sales
50
 
91
Oklahoma Resource Basins:
 
 
 
Wells drilled to total depth
5
 
8
Wells brought to sales
3
 
5
Bakken:
 
 
 
Wells drilled to total depth
3
 
20
Wells brought to sales
6
 
24
•
Eagle Ford – Of the 50 gross operated wells brought to sales during the first quarter of 2016, 23 were Lower Eagle Ford, 19 were Upper Eagle Ford and 8 were Austin Chalk. Our average time to drill an Eagle Ford well in the first quarter 2016, spud-to-total depth, decreased to 8 days from 12 days in the same quarter last year as efficiency gains in drilling continued. Wells were drilled at an average rate of 2,300 feet per day and the top-performing Eagle Ford rigs drilled four wells in excess of 3,300 feet per day.
•
Oklahoma Resource Basins – In the first quarter of 2016, we continued our focus on leasehold protection and delineation and brought 3 gross operated wells to sales, of which one was in the SCOOP Woodford, one in the SCOOP Springer and one in the STACK Meramec. We also participated in 7 outside-operated wells during the first quarter of 2016 that were focused in SCOOP and STACK.
•
Bakken –  The 6 gross operated wells brought to sales in the first quarter of 2016 were in the greater Hector area, of which 4 were in Middle Bakken and 2 in Three Forks. Our average time to drill a Bakken well in the first quarter of 2016, spud-to-total depth, decreased to 12 days from 17 days in the first quarter of 2015. We released the remaining drilling rig in February and expect reduced completions activity during the second quarter.
•
Other North America – Net sales volumes declined in the first quarter of 2016 primarily due to the 2015 sales of the non-core assets in the Gulf of Mexico and East Texas, North Louisiana and Wilburton, Oklahoma. Additionally, development work continues in the Gunflint field located in Mississippi Canyon. First oil is expected in the second half of 2016 after the completion of work at a third party facility. We hold an 18% non-operated working interest in the Gunflint field.
International E&P
Net sales volumes in the segment were lower in the first quarter of 2016 primarily as a result of planned downtime in E.G. and repairs at Brae Alpha in the U.K. The following table provides details regarding net sales volumes for our significant operations within this segment.
 
Three Months Ended March 31,
Net Sales Volumes
2016
 
2015
 
Increase
(Decrease)
Equivalent Barrels (mboed)
 
 
 
 
 
Equatorial Guinea
84
 
97
 
(13)%
United Kingdom(a)
12
 
19
 
(37)%
Total International E&P
96
 
116
 
(17)%
Equity Method Investees
 
 
 
 
 
LNG (mtd)
4,322
 
6,275
 
(31)%
Methanol (mtd)
1,280
 
884
 
45%
Condensate & LPG (boed)
10,208
 
13,223
 
(23)%
(a) 
Includes natural gas acquired for injection and subsequent resale of 5 mmcfd and 10 mmcfd for the first quarters of 2016 and 2015.
•
Equatorial Guinea – First quarter 2016 net sales were reduced compared to prior year quarter due to planned downtime associated with the installation of the Alba compression jacket and topsides, and planned maintenance activities in the onshore plants. This planned maintenance was successfully completed under budget and ahead of schedule. The ongoing Alba field compression project, designed to maintain the production plateau for an additional two years and extend field life up to eight years, remains on schedule with first production mid-year.

19

•
United Kingdom – Net sales volumes in first quarter 2016 were lower as a result of repairs at Brae Alpha which was shut-in throughout the quarter following a process pipe failure in late 2015, partially offset by improved reliability from the outside-operated Foinaven field. Full production from Brae Alpha resumed in late April.
•
Libya – Due to continued civil unrest, there were no liftings during the quarter. Considerable uncertainty remains around the timing of future production and sales levels.
Oil Sands Mining
 Our net synthetic crude oil sales volumes were 59 mbbld first quarter of 2016 compared to 60 mbbld in the same period of 2015. Planned maintenance activities began ahead of schedule in mid-March at the base upgrader and the Jackpine mine which will impact production in the second quarter. In addition, in early May our operations at the Muskeg River and Jackpine mines have been suspended to support emergency response efforts related to the Fort McMurray area wildfires. The mines are approximately 60 miles north of the wildfires and not currently threatened by fire. We hold a 20% non-operated working interest in the Athabasca Oil Sands Project. 

 

20


Market Conditions
Prevailing prices for the crude oil, NGLs and natural gas that we produce significantly impact our revenues and cash flows. The benchmark prices for crude oil, NGLs and natural gas were lower in the first quarter of 2016 as compared to the same period in 2015; as a result, we experienced declines in our price realizations associated with those benchmarks. Additional detail on market conditions, including our average price realizations and benchmarks for crude oil, NGLs and natural gas relative to our operating segments, follows.
North America E&P
 The following table presents our average price realizations and the related benchmarks for crude oil, NGLs and natural gas for the first quarter of 2016 and 2015.
 
Three Months Ended March 31,
 
2016
 
2015
 
Increase (Decrease)
Average Price Realizations (a)
 
 
 
 
 
Crude Oil and Condensate (per bbl) (b)
$28.21
 
$41.75
 
(32
)%
Natural Gas Liquids (per bbl)
8.12

 
14.43

 
(44
)%
Total Liquid Hydrocarbons (per bbl)
24.00

 
36.92

 
(35
)%
Natural Gas (per mcf)
2.02

 
3.01

 
(33
)%
Benchmarks
 
 
 
 
 
WTI crude oil (per bbl)

$33.63

 

$48.58

 
(31
)%
LLS crude oil (per bbl)
35.33

 
52.84

 
(33
)%
Mont Belvieu NGLs (per bbl) (c)
13.95

 
18.39

 
(24
)%
Henry Hub natural gas (per mmbtu)
2.09

 
2.98

 
(30
)%
(a) 
Excludes gains or losses on commodity derivative instruments.
(b) 
Inclusion of realized gains on crude oil derivative instruments would have increased average realizations by $1.64 per bbl and $0.21 per bbl for the first quarter 2016 and 2015.
(c) 
Bloomberg Finance LLP: Y-grade Mix NGL of 50% ethane, 25% propane, 10% butane, 5% isobutane and 10% natural gasoline.
Crude oil and condensate – Our crude oil and condensate price realizations may differ from the benchmark due to the quality and location of the product.
Natural gas liquids – The majority of our NGL volumes are sold at reference to Mont Belvieu prices.
Natural gas – A significant portion of our natural gas production in the U.S. is sold at bid-week prices, or first-of-month indices relative to our specific producing areas.  
International E&P
The following table presents our average price realizations and the related benchmark for crude oil, NGLs, and natural gas for the first quarter of 2016 and 2015.
 
Three Months Ended March 31,
 
2016
 
2015
 
Increase
(Decrease)
Average Price Realizations
 
 
 
 
 
Crude Oil and Condensate (per bbl)
$30.95
 
$48.87
 
(37
)%
Natural Gas Liquids (per bbl)
2.20

 
3.46

 
(36
)%
Liquid Hydrocarbons (per bbl)
22.66

 
37.31

 
(39
)%
Natural Gas (per mcf)
0.60

 
0.78

 
(23
)%
Benchmark
 
 
 
 


Brent (Europe) crude oil (per bbl) (a)

$33.70

 

$53.92

 
(38
)%
(a) 
Average of monthly prices obtained from EIA website.
Liquid hydrocarbons – Our U.K. liquid hydrocarbon production is generally sold in relation to the Brent crude benchmark. Our production from Equatorial Guinea is condensate, which receives lower prices than crude oil.

21


Our NGL and natural gas sales in the International E&P segment originate primarily from our E.G. operations and are sold to our equity method investees under fixed-price, term contracts; therefore, our reported average realized prices for NGLs and natural gas will not fully track market price movements. The equity affiliates then utilize, process and sell the NGLs and natural gas at market prices, with our share of their income/loss reflected in the Income from equity method investments line item on the Consolidated Statements of Income.
Oil Sands Mining
The Oil Sands Mining segment produces and sells various qualities of synthetic crude oil. Output mix can be impacted by operational reliability or planned unit outages at the mines or upgrader. Sales prices for roughly two-thirds of the normal output mix have historically tracked movements in WTI and one-third have historically tracked movements in the Canadian heavy crude oil marker, primarily WCS.
The following table presents our average price realizations and the related benchmarks for the first quarter of 2016 and 2015.
 
Three Months Ended March 31,
 
2016
 
2015
 
Increase (Decrease)
Average Price Realizations
 
 
 
 
 
Synthetic Crude Oil (per bbl)

$26.41

 

$40.37

 
(35
%)
Benchmarks
 
 
 
 
 
WTI crude oil (per bbl)

$33.63

 

$48.58

 
(31
%)
WCS crude oil (per bbl)(a) 
19.21

 
33.90

 
(43
%)
(a) 
Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.

22


Results of Operations
Three Months Ended March 31, 2016 vs. Three Months Ended March 31, 2015
Sales and other operating revenues, including related party are presented by segment in the table below:
 
Three Months Ended March 31,
(In millions)
2016
 
2015
Sales and other operating revenues, including related party
 
 
 
North America E&P
$
493

 
$
850

International E&P
96

 
182

Oil Sands Mining
148

 
225

Segment sales and other operating revenues, including related party
$
737

 
$
1,257

Unrealized (loss) gain on crude oil derivative instruments
(23
)
 
23

Sales and other operating revenues, including related party
$
714

 
$
1,280

Below is a price/volume analysis for each segment. Refer to the preceding Operations and Market Conditions sections for additional detail related to our net sales volumes and average price realizations.
 
 
Three Months Ended
 
Increase (Decrease) Related to
 
Three Months Ended
(In millions)
 
March 31, 2015
 
Price Realizations
 
Net Sales Volumes
 
March 31, 2016
North America E&P Price-Volume Analysis
Liquid hydrocarbons
 
$
741

 
$
(220
)
 
$
(113
)
 
$
408

Natural gas
 
97

 
(29
)
 
(11
)
 
57

Realized gain on crude oil
 
 
 
 
 
 
 
 
    derivative instruments
 
3

 
19

 


 
22

Other sales
 
9

 


 


 
6

Total
 
$
850

 
 
 
 
 
$
493

International E&P Price-Volume Analysis
Liquid hydrocarbons
 
$
139

 
$
(43
)
 
$
(30
)
 
$
66

Natural gas
 
32

 
(6
)
 
(5
)
 
21

Other sales
 
11

 
 
 
 
 
9

Total
 
$
182

 
 
 
 
 
$
96

Oil Sands Mining Price-Volume Analysis
Synthetic crude oil
 
$
217

 
$
(74
)
 
$
—

 
$
143

Other sales
 
8

 


 


 
5

Total
 
$
225

 
 
 
 
 
$
148

Marketing revenues decreased $146 million in the first quarter of 2016 from the comparable prior-year period. Marketing activities include the purchase of commodities from third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points. Since the volume of marketing activity is based on market dynamics, it can fluctuate from period to period. The decreases are related primarily to lower marketed volumes in North America, which were further compounded by a lower commodity price environment.
Income from equity method investments decreased $22 million in the first quarter of 2016 from the comparable 2015 period. The decrease is primarily due to lower net sales volumes as a result of planned downtime at E.G. as a result of the Alba field compression project which impacted our equity method plants. Also impacting the quarter were lower price realizations for LPG at our Alba plant and lower methanol prices at our AMPCO methanol facility.
Net loss on disposal of assets in the first quarter of 2016 was related to the sale of non-core assets. See Note 5 to the consolidated financial statements for information about dispositions.
Production expenses decreased $116 million. North America E&P declined $68 million primarily due to lower operational, maintenance and labor costs, coupled with the 2015 disposition of certain producing Gulf of Mexico assets. International E&P declined $14 million primarily as a result of lower operational costs in Libya and lower costs in the U.K. associated with lower net sales volumes, which was offset by higher planned maintenance costs in E.G. during the first quarter of 2016. OSM decreased $34 million primarily due to a more favorable exchange rate on expenses denominated in the Canadian Dollar and continued cost management, especially staffing and contract labor.

23


The first quarter of 2016 production expense rate (expense per boe) for North America E&P declined as cost reductions occurred at a rate faster than our production decline. The expense rate for International E&P declined due to reduced maintenance and project costs and lower operational costs in Libya. The OSM expense rate decreased due to the positive currency effects and the increased cost focus, as discussed above.
The following table provides production expense rates for each segment:
 
Three Months Ended March 31,
($ per boe)
2016
 
2015
Production Expense Rate
 
 
 
North America E&P

$6.17

 

$7.94

International E&P

$6.08

 

$6.40

Oil Sands Mining (a)

$28.80

 

$34.78

(a) 
Production expense per synthetic crude oil barrel (before royalties) includes direct production costs (less pre-development), shipping and handling and taxes other than income.
Marketing costs decreased $147 million in the first quarter of 2016 from the comparable 2015 period, consistent with the marketing revenues changes discussed above.
 Exploration expenses decreased $66 million primarily due to higher dry well costs in the first quarter of 2015 which included the Sodalita West #1 well in E.G. and the Key Largo well in the Gulf of Mexico. The following table summarizes the components of exploration expenses:
 
Three Months Ended March 31,
(In millions)
2016
 
2015
Exploration Expenses
 
 
 
Unproved property impairments
$
11

 
$
9

Dry well costs
—

 
58

Geological and geophysical
—

 
3

Other
13

 
20

Total exploration expenses
$
24

 
$
90

Depreciation, depletion and amortization decreased $212 million primarily as a result of production volume decreases, a higher proved reserve base in Eagle Ford and as a result of the Gulf of Mexico disposition in 2015 discussed above. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, proved reserve and production volumes have an impact on DD&A expense.
The DD&A rate (expense per boe), which is impacted by changes in reserves, capitalized costs, and sales volume mix by field, can also cause changes to our DD&A. The following table provides DD&A rates for each segment. The DD&A rate for North America E&P decreased primarily as a result of a higher proved reserve base in Eagle Ford.
 
Three Months Ended March 31,
($ per boe)
2016
 
2015
DD&A Rate
 
 
 
North America E&P

$22.39

 

$26.85

International E&P

$5.68

 

$6.10

Oil Sands Mining

$11.30

 

$12.44



24


Taxes other than income decreased $19 million in the first quarter of 2016. The following table summarizes the components of taxes other than income:
 
Three Months Ended March 31,
(In millions)
2016
 
2015
Production and severance
$
19

 
$
34

Ad valorem
13

 
16

Other
16

 
17

Total
$
48

 
$
67

General and administrative expenses decreased $20 million primarily due to cost savings realized from the workforce reductions in 2015, as well as lower severance related expenses in the current year. This was partially offset by pension settlement charges in the first three months of 2016 which totaled $48 million compared to $17 million in the prior year.
Net interest and other increased $38 million primarily due to higher net foreign currency loss and increased interest expense associated with our June 2015 debt issuance.
Provision (benefit) for income taxes reflects an effective tax rate of 40% in the first quarter of 2016, as compared to 34% in the first quarter of 2015. See Note 8 to the consolidated financial statements for discussion of the effective tax rate.
Segment Income (Loss)
Segment income (loss) represents income (loss) from operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments, unrealized gains or losses on commodity derivative instruments, or other items that affect comparability also are not allocated to operating segments.
The following table reconciles segment income (loss) to net income (loss):
 
Three Months Ended March 31,
(In millions)
2016
 
2015
North America E&P
$
(195
)
 
$
(161
)
International E&P
4

 
23

Oil Sands Mining
(48
)
 
(19
)
Segment income (loss)
(239
)
 
(157
)
Items not allocated to segments, net of income taxes
(168
)
 
(119
)
Net income (loss)
$
(407
)
 
$
(276
)
 North America E&P segment loss increased $34 million after-tax primarily due to lower price realizations and sales volumes, which was partially offset by lower DD&A and production expenses.
International E&P segment income decreased $19 million after-tax primarily due to lower price realizations and sales volumes as well as reduced income from equity investments. These declines were partially offset by lower exploration, production and DD&A expenses.
Oil Sands Mining segment loss increased $29 million after-tax primarily due to lower price realizations, partially offset by lower production expenses.
Critical Accounting Estimates 
There have been no material changes or developments in the evaluation of the accounting estimates and the underlying assumptions or methodologies pertaining to our Critical Accounting Estimates disclosed in our Form 10-K for the year ended December 31, 2015, except as discussed below.
Fair Value Estimates - Goodwill
Goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. A triggering event related to price declines in our common stock required us to reassess our goodwill for impairment as of March 31, 2016. Based on the results of this assessment, we concluded no impairment was required. While the fair value of our International E&P reporting unit exceeded book value, subsequent commodity price and/or common stock declines may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.

25


Estimated Quantities of Net Reserves
Our December 31, 2015 proved reserves were calculated using the unweighted average of closing benchmark prices nearest to the first day of each month within the 12-month period ("SEC pricing"). The table below provides the 2015 SEC pricing for certain benchmark prices as well as the unweighted average for the first four months of 2016:
 
Unweighted 12-month 2015 Average
Unweighted 4-month 2016 Average
WTI Crude oil
$50.28
$35.67
Henry Hub natural gas
2.59
2.00
Brent crude oil
54.25
35.95
Natural gas liquids
17.32
13.16
Any significant future price change could have a material effect on the quantity and present value of our proved reserves. To the extent that commodity prices remain at lower levels throughout 2016, a portion of our proved reserves could be deemed uneconomic and no longer classified as proved. This could impact both proved developed producing reserves as well as proved undeveloped reserves. If prices remain at the 4-month average depicted above throughout 2016, a material volume of our proved reserves could become uneconomic and would have to be reclassified to non-proved reserve or resource category. Assuming lower SEC pricing in 2016, our OSM proved reserves represent the largest risk to be reclassified to non-proved reserve or resource category. However, any impact of lower SEC pricing will likely be partially offset by continued cost reduction efforts. Also, any volumes reclassified to non-proved reserves could return to proved reserves as commodity prices improve. In the event the OSM proved reserves are reclassified to non-proved reserves or resource, their classification will have no impact on future plans for production.
Accounting Standards Not Yet Adopted
See Note 2 to the consolidated financial statements.
Cash Flows
The following table presents sources and uses of cash and cash equivalents:
 
Three Months Ended March 31,
(In millions)
2016
2015
Sources of cash and cash equivalents
 

 

Operating activities
$
74

$
309

Common stock issuance
1,232

—

Disposals of assets
17

2

Other
16

14

Total sources of cash and cash equivalents
$
1,339

$
325

Uses of cash and cash equivalents
 
 
Cash additions to property, plant and equipment
$
(454
)
$
(1,452
)
Dividends paid
(34
)
(142
)
Other
—

(3
)
Total uses of cash and cash equivalents
$
(488
)
$
(1,597
)
Cash flows generated from operating activities in the first quarter of 2016 were lower as the downturn in the commodity cycle continued. This continued downward pressure on price realizations, coupled with the lower net sales volumes, continues to negatively impact our cash flows from operating activities. In the first quarter of 2016, consolidated average liquids price realizations were down by approximately 35% and consolidated net sales volumes declined by 14% as compared to the prior year quarter.
Common stock issuance reflects net proceeds received in March 2016 from our public sale of common stock. See Liquidity and Capital Resources below for additional information.

26


Additions to property, plant and equipment are our most significant use of cash and cash equivalents. Total capital expenditures, including accruals, were 67% lower in the first quarter of 2016 consistent with a reduced Capital Program as compared to the prior year. The following table shows capital expenditures by segment and reconciles to additions to property, plant and equipment as presented in the consolidated statements of cash flows:
 
Three Months Ended March 31,
(In millions)
2016
 
2015
North America E&P
$
315

 
$
933

International E&P
32

 
146

Oil Sands Mining
9

 
21

Corporate
3

 
2

Total capital expenditures
359

 
1,102

Decrease in capital expenditure accrual
95

 
350

Total use of cash and cash equivalents for property, plant and equipment
$
454

 
$
1,452

In October 2015, we announced an adjustment to our quarterly dividend. See Capital Requirements below for additional information.
Liquidity and Capital Resources
In March 2016, we issued 166,750,000 shares of our common stock, par value $1 per share, at a price of $7.65 per share, excluding underwriting discounts and commissions, for net proceeds of $1,232 million. The proceeds will be used to strengthen our balance sheet and for general corporate purposes, including funding a portion of our Capital Program.
Also in March 2016, we increased our $3.0 billion unsecured Credit Facility by $300 million to a total of $3.3 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the increase.
Our main sources of liquidity are cash and cash equivalents, sales of non-core assets, internally generated cash flow from operations, capital market transactions, and our $3.3 billion Credit Facility. Our working capital requirements are supported by these sources and we may draw on our $3.3 billion Credit Facility to meet short-term cash requirements, or issue debt or equity securities through the shelf registration statement discussed below as part of our longer-term liquidity and capital management. Because of the alternatives available to us as discussed above, we believe that our short-term and long-term liquidity is adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, and other amounts that may ultimately be paid in connection with contingencies.
Due to decreases in crude oil and U.S. natural gas prices earlier this year, credit rating agencies recently reviewed many companies in the industry, including us. During the first quarter of 2016, our corporate credit rating was downgraded by: Standard & Poor's Ratings Services to BBB- (stable) from BBB (stable); by Fitch Ratings to BBB (negative) from BBB+ (stable); and by Moody's Investor Services, Inc. to Ba1 (negative) from Baa1 (stable). Any further rating downgrades could increase our future cost of financing or limit our ability to access capital. See Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2015 for a discussion of how a further downgrade in our credit ratings could affect us.
Capital Resources
Credit Arrangements and Borrowings
At March 31, 2016, we had no borrowings against our revolving credit facility.
At March 31, 2016, we had $7.3 billion in long-term debt outstanding, with our next debt maturity in the amount of $680 million due in the fourth quarter of 2017.
We do not have any triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit ratings.
Shelf Registration
We have a universal shelf registration statement filed with the SEC under which we, as a "well-known seasoned issuer" for purposes of SEC rules, have the ability to issue and sell an indeterminate amount of various types of equity and debt securities. 


27


Asset Disposals
Since August 2015, we have announced or closed non-core asset sales of approximately $1.3 billion, surpassing our targeted range of $750 million to $1 billion. In the largest transaction, we will divest all of our Wyoming upstream and midstream assets for $870 million, before closing adjustments, with closing expected mid-year 2016. In separate transactions, we signed agreements for the sale of our 10% working interest in the outside-operated Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Colorado, and certain undeveloped acreage in West Texas for a combined total of approximately $80 million, before closing adjustments, with closing expected mid-year 2016.
Cash-Adjusted Debt-To-Capital Ratio
 Our cash-adjusted debt-to-capital ratio (total debt-minus-cash and cash equivalents to total debt-plus-equity-minus-cash and cash equivalents) was 21% at March 31, 2016, compared to 25% at December 31, 2015.
 
March 31,
 
December 31,
(In millions)
2016
 
2015
Long-term debt due within one year
$
1

 
$
1

Long-term debt
7,280

 
7,276

Total debt
$
7,281

 
$
7,277

Cash and cash equivalents
$
2,072

 
$
1,221

Equity
$
19,351

 
$
18,553

Calculation:
 

 
 

Total debt
$
7,281

 
$
7,277

Minus cash and cash equivalents
2,072

 
1,221

Total debt minus cash, cash equivalents
$
5,209

 
$
6,056

Total debt
$
7,281

 
$
7,277

Plus equity
19,351

 
18,553

Minus cash and cash equivalents
2,072

 
1,221

Total debt plus equity minus cash, cash equivalents
$
24,560

 
$
24,609

Cash-adjusted debt-to-capital ratio
21
%
 
25
%
Capital Requirements
Our Board of Directors approved a Capital Program of $1.4 billion for 2016.
On April 27, 2016, our Board of Directors approved a dividend of $0.05 per share for the first quarter of 2016 payable June 10, 2016 to stockholders of record at the close of business on May 18, 2016.
As of March 31, 2016, we plan to make contributions of up to $48 million to our funded pension plans during the remainder of 2016.
Contractual Cash Obligations
As of March 31, 2016, there are no material changes to our consolidated cash obligations to make future payments under existing contracts, as disclosed in our 2015 Annual Report on Form 10-K.
 
 
 
 
 
 
 
 
 
 
Environmental Matters 
We have incurred and will continue to incur capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations.  If these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected.  We believe that substantially all of our competitors must comply with similar environmental laws and regulations.  However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes.
There have been no significant changes to our environmental matters subsequent to December 31, 2015.
Other Contingencies
We are a defendant in a number of legal and administrative proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims, tax disputes and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.  

28


Forward-Looking Statements
This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the "Exchange Act"). All statements other than statements of historical fact included or incorporated by reference in this report are forward-looking statements, including without limitation statements regarding: our operational and financial strategies, including project plans, drilling plans, maintenance activities, financial flexibility, strengthening of the balance sheet, productivity improvements, and drilling and completion efficiencies; our ability to effect those strategies and the expected timing and results thereof; our ability to complete the non-core asset sales, and the expected timing and results thereof; our financial and operational outlook and ability to fulfill that outlook; expectations regarding future economic and market conditions and their effects on our business; our 2016 Capital Program; our financial position, liquidity and capital resources; and the plans and objectives of our management for our future operations. In addition, many forward-looking statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “estimate,” “expect,” “target,” “plan,” “project,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. While we believe that our assumptions concerning future events are reasonable, a number of factors could cause results to differ materially from those indicated by such forward-looking statements including, but not limited to:
•
conditions in the oil and gas industry, including supply/demand levels and the resulting impact on price;
•
changes in expected reserve or production levels;
•
changes in political or economic conditions in the jurisdictions in which we operate;
•
capital available for exploration and development;
•
well production timing;
•
availability of drilling rigs, materials and labor;
•
difficulty in obtaining necessary approvals and permits;
•
non-performance by third parties of contractual obligations;
•
unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto;
•
cyber-attacks;
•
changes in safety, health, environmental and other regulations;
•
other geological, operating and economic considerations; and
•
the risk factors, forward-looking statements and challenges and uncertainties described in our 2015 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other filings with the SEC.
All forward-looking statements included in this report are based on information available to us on the date of this report. Except as required by law, we assume no duty or obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.

29


Item 3. Quantitative and Qualitative Disclosures About Market Risk
For a detailed discussion of our risk management strategies and our derivative instruments, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk in our 2015 Annual Report on Form 10-K. Additional disclosures regarding our open derivative positions, including underlying notional quantities, how they are reported in our consolidated financial statements and how their fair values are measured, may be found in Notes 11 and 12 to the consolidated financial statements.
Commodity Price Risk During the first three months of 2016, we entered into crude oil and natural gas derivatives, indexed to NYMEX WTI and Henry Hub, related to a portion of our forecasted North America E&P sales. The following tables provide a summary of open positions as of March 31, 2016 and the weighted average price for those contracts:
Crude Oil (a)
 
2016
Year Ending December 31,
 
Second Quarter
Third Quarter
Fourth Quarter
2017
Three-Way Collars (b)
Volume (Bbls/day)
39,000
37,000
37,000
—
Price per Bbl
 
 
 
 
Ceiling
$55.47
$54.52
$54.52
—
Floor
$51.56
$50.83
$50.83
—
Sold put
$41.67
$41.22
$41.22
—
Options (c)
 
 
 
 
Volume (Bbls/day)
10,000
10,000
10,000
25,000
Price per Bbl
$72.39
$72.39
$72.39
$60.67
Swaps
 
 
 
 
Volume (Bbls/day)
25,000
—
—
—
Price per Bbl
$39.25
—
—
—
(a) Subsequent to March 31, 2016, we entered into 10,000 Bbls/day of two-way collars for July - December 2016 with a ceiling price of $50.00 and a floor price of $41.55. We also entered into 10,000 Bbls/day of 2016 three-way collars for May - December 2016 with a ceiling price of $58.51, a floor price of $48.00, and a sold put price of $40.00, traded in conjunction with sold call options of 10,000 Bbls/day for 2017 at $65.00.
(b) 
A counterparty has the option, exercisable on June 30, 2016, to extend three-way collars for 2,000 Bbls/day through the remainder of 2016 at a ceiling of $73.13, floor of $65.00 and sold put of $50.00.
(c) 
Call options settle monthly.
Natural Gas (a)
 
2016
Year Ending December 31,
 
Second Quarter
Third Quarter
Fourth Quarter
2017
Three-Way Collars (b)
 
 
 
 
Volume (MMBtu/day)
20,000
20,000
20,000
20,000
Price per MMBtu
 
 
 
 
Ceiling
$2.93
$2.93
$2.93
$3.07
Floor
$2.50
$2.50
$2.50
$2.75
Sold put
$2.00
$2.00
$2.00
$2.25
(a) 
Subsequent to March 31, 2016, we entered into 20,000 MMBtu/day of 2017 three-way collars with a ceiling price of $3.50, a floor price of $2.75, and a sold put price of $2.25.
(b) 
Counterparty has the option to execute fixed-price swaps (swaptions) at a weighted average price of $2.93 per MMBtu indexed to NYMEX Henry Hub, which is exercisable on December 22, 2016. If counterparty exercises, the term of the fixed-price swaps would be for the calendar year 2017 and, if all such options are exercised, 20,000 MMBtu per day.

The following table provides a sensitivity analysis of the projected incremental effect on income (loss) from operations of a hypothetical 10% change in NYMEX WTI and Henry Hub prices on our open commodity derivative instruments as of March 31, 2016.

30


(In millions)
Hypothetical Price Increase of 10%
Hypothetical Price Decrease of 10%
 
 
 
Crude oil derivatives
$
(46
)
$
38

Natural gas derivatives
(3
)
3

Total
$
(49
)
$
41


Interest Rate Risk Sensitivity analysis of the incremental effect of a hypothetical 10% change in interest rates on financial assets and liabilities as of March 31, 2016, is provided in the following table.
(In millions)
Fair Value
 
Incremental Change in Fair Value
Financial assets (liabilities): (a)
 
 
 
Interest rate swap agreements
$
12

(b) 
$
1

Long term debt, including amounts due within one year
$
(6,575
)
(b)(c) 
$
(310
)
(a) 
Fair value of cash and cash equivalents, receivables, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.
(b) 
Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.
(c) 
Excludes capital leases.
    
Item 4. Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer.  As of the end of the period covered by this Report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as of March 31, 2016.  
During the first quarter of 2016, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

31


Part II – OTHER INFORMATION
Item 1. Legal and Administrative Proceedings
We are a defendant in a number of legal and administrative proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims, tax disputes and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.  
Item 1A. Risk Factors
We are subject to various risks and uncertainties in the course of our business.  There have been no material changes to the risk factors under Item 1A. Risk Factors in our 2015 Annual Report on Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table provides information about purchases by Marathon Oil during the quarter ended March 31, 2016, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Exchange Act of 1934.
 
Total Number of
 
Average Price
 
Total Number of
Shares Purchased
as Part of
Publicly Announced
 
Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Period
Shares Purchased (a)
 
Paid per Share
 
 Plans or Programs
 
Plans or Programs
01/01/16 - 01/31/16
4,032

 
$12.96
 
—

 
n/a
02/01/16 - 02/29/16
7,402

 
$8.01
 
—

 
n/a
03/01/16 - 03/31/16
290

 
$7.82
 
—

 
n/a
Total
11,724

 
$9.71
 
—

 
 
(a) 
11,724 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.
Item 6.  Exhibits
The information required by this Item 6 is set forth in the Exhibit Index accompanying this Form 10-Q.

32


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.
May 5, 2016
 
MARATHON OIL CORPORATION
 
 
 
 
By:
/s/ Gary E. Wilson
 
 
Gary E. Wilson
 
 
Vice President, Controller and Chief Accounting Officer
 
 
(Duly Authorized Officer)

33


Exhibit Index
 
 
 
Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
Exhibit Number
 
Exhibit Description
Form
 
Exhibit
 
Filing Date
 
3.1
 
Restated Certificate of Incorporation of Marathon Oil Corporation
10-Q
 
3.1
 
8/8/2013
 
3.2
 
Marathon Oil Corporation By-laws (Amended and restated as of February 24, 2016)
8-K
 
3.1
 
3/1/2016
 
3.3
 
Specimen of Common Stock Certificate
10-K
 
3.3
 
2/28/2014
 
4.1
 
Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the SEC upon its request
10-K
 
4.1
 
2/28/2014
 
12.1
 
Computation of Ratio of Earnings to Fixed Charges*
 
 
 
 
 
 
31.1
 
Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934*
 
 
 
 
 
 
31.2
 
Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934*
 
 
 
 
 
 
32.1
 
Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350*
 
 
 
 
 
 
32.2
 
Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350*
 
 
 
 
 
 
101.INS
 
XBRL Instance Document*
 
 
 
 
 
 
101.SCH
 
XBRL Taxonomy Extension Schema*
 
 
 
 
 
 
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase*
 
 
 
 
 
 
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase*
 
 
 
 
 
 
101.LAB
 
XBRL Taxonomy Extension Label Linkbase*
 
 
 
 
 
 
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase*
 
 
 
 
 
 
*
 
Filed herewith.
 
 
 
 
 
 



Exhibit 12.1


MARATHON OIL CORPORATION
Computation of Ratio of Earnings to Fixed Charges (Unaudited)

 
 
Three Months Ended
 
Year Ended
 
 
March 31,
 
December 31,
(In millions)
 
2016
 
2015
 
2014
 
2013
 
2012
 
2011
 
 
 
 
 
 
 
 
 
 
 
 
 
Income (loss) from continuing operations before income taxes
 
$
(683
)
 
$
(2,958
)
 
$
1,361

 
$
2,393

 
$
3,104

 
$
1,615

Income from equity method investments
 
14

 
145

 
424

 
423

 
370

 
462

Income (loss) from continuing operations before income taxes and income from equity method investments
 
(697
)
 
(3,103
)
 
937

 
1,970

 
2,734

 
1,153

Add (deduct)
 
 
 
 
 
 
 
 
 
 
 
 
Fixed charges
 
102

 
382

 
352

 
360

 
338

 
504

Capitalized interest
 
(7
)
 
(26
)
 
(33
)
 
(27
)
 
(68
)
 
(208
)
Amortization of capitalized interest
 
1

 
5

 
8

 
21

 
45

 
107

Distributed income from equity investees
 
44

 
178

 
454

 
430

 
382

 
499

Earnings as defined
 
(557
)
 
(2,564
)
 
1,718

 
2,754

 
3,431

 
2,055

 
 
 
 
 
 
 
 
 
 
 
 
 
Net interest expense (including discontinued operations)
 
88

 
321

 
277

 
297

 
236

 
245

Capitalized interest (including discontinued operations)
 
7

 
26

 
33

 
27

 
68

 
208

Interest portion of rental expense (including discontinued operations)
 
7

 
35

 
42

 
36

 
34

 
51

Fixed charges as defined
 
102

 
382

 
352

 
360

 
338

 
504

 
 
 
 
 
 
 
 
 
 
 
 
 
Ratio of earnings to fixed charges
 
(5.46
)
 
(6.71
)
 
4.88

 
7.65

 
10.15

 
4.08

 
 
 
 
 
 
 
 
 
 
 
 
 
Amount by which earnings were insufficient to cover fixed charges
 
$
659

 
$
2,946

 
$
—

 
$
—

 
$
—

 
$
—






Exhibit 31.1 
MARATHON OIL CORPORATION 

CERTIFICATION PURSUANT TO SECTION 302 OF
THE SARBANES-OXLEY ACT OF 2002
I, Lee M. Tillman, certify that: 

1.
I have reviewed this report on Form 10-Q of Marathon Oil 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.
Date:
May 5, 2016
 
/s/ Lee M. Tillman
 
 
 
Lee M. Tillman
 
 
 
President and Chief Executive Officer





Exhibit 31.2 
MARATHON OIL CORPORATION 

CERTIFICATION PURSUANT TO SECTION 302 OF
THE SARBANES-OXLEY ACT OF 2002 
 I, John R. Sult, certify that:

1.
I have reviewed this report on Form 10-Q of Marathon Oil 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.
Date:
May 5, 2016
 
/s/ John R. Sult
 
 
 
John R. Sult
 
 
 
Executive Vice President and Chief Financial Officer





Exhibit 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002


In connection with the Quarterly Report of Marathon Oil Corporation (the “Company”) on Form 10-Q for the period ending March 31, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Lee M. Tillman, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1)
The 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 5, 2016
 
 
 
/s/ Lee M. Tillman
 
Lee M. Tillman
 
President and Chief Executive Officer
 





Exhibit 32.2

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

    
In connection with the Quarterly Report of Marathon Oil Corporation (the “Company”) on Form 10-Q for the period ending March 31, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John R. Sult, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1)
The 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 5, 2016
 
 
 
/s/ John R. Sult
 
John R. Sult
 
Executive Vice President and Chief Financial Officer
 



v3.4.0.3
Document and Entity Information - shares
 3 Months Ended
Mar. 31, 2016
Apr. 29, 2016
Document and Entity Information [Abstract]    
Document Type 10-Q  
Document Period End Date Mar. 31, 2016  
Document Fiscal Period Focus Q1  
Document Fiscal Year Focus 2016  
Amendment Flag false  
Entity Registrant Name Marathon Oil Corp  
Entity Central Index Key 0000101778  
Entity Current Reporting Status Yes  
Entity Voluntary Filers No  
Current Fiscal Year End Date --12-31  
Entity Filer Category Large Accelerated Filer  
Entity Well Known Seasoned Issuer Yes  
Entity Common Stock Shares Outstanding   847,648,273
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 income:    
Sales and other operating revenues, including related party $ 714 $ 1,280
Marketing revenues 58 204
Income from equity method investments 14 36
Net gain (loss) on disposal of assets (60) 1
Other income 4 11
Total revenues and other income 730 1,532
Costs and expenses:    
Production 328 444
Marketing, including purchases from related parties 58 205
Other operating 109 107
Exploration 24 90
Depreciation, depletion and amortization 609 821
Impairments 1 0
Taxes other than income 48 67
General and administrative 151 171
Total costs and expenses 1,328 1,905
Income (loss) from operations (598) (373)
Net interest and other (85) (47)
Income (loss) before income taxes (683) (420)
Provision (benefit) for income taxes (276) (144)
Income (loss) from operations (407) (276)
Net income (loss) $ (407) $ (276)
Basic:    
Net income (loss), per basic share $ (0.56) $ (0.41)
Diluted:    
Net income (loss), per diluted share (0.56) (0.41)
Dividends paid, per share $ 0.05 $ 0.21
Weighted average common shares outstanding, basic 730 675
Weighted average common shares outstanding, diluted 730 675
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) $ (407) $ (276)
Postretirement and postemployment plans    
Change in actuarial loss and other (24) 76
Income tax benefit (provision) on postretirement and postemployment plans 9 (27)
Postretirement and postemployment plans, net of tax (15) 49
Comprehensive loss $ (422) $ (227)
v3.4.0.3
Consolidated Balance Sheets - USD ($)
$ in Millions
Mar. 31, 2016
Dec. 31, 2015
Current assets:    
Cash and cash equivalents $ 2,072 $ 1,221
Receivables, less reserve of $4 and $4 779 912
Inventories 306 313
Other current assets 111 144
Total current assets 3,268 2,590
Equity method investments 959 1,003
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $22,763 and $23,260 26,737 27,061
Goodwill 115 115
Other noncurrent assets 1,789 1,542
Total assets 32,868 32,311
Current liabilities:    
Accounts payable 1,084 1,313
Payroll and benefits payable 79 133
Accrued taxes 151 132
Other current liabilities 211 150
Long-term debt due within one year 1 1
Total current liabilities 1,526 1,729
Long-term debt 7,280 7,276
Deferred tax liabilities 2,368 2,441
Defined benefit postretirement plan obligations 446 403
Asset retirement obligations 1,614 1,601
Deferred credit and other liabilities 283 308
Total liabilities $ 13,517 $ 13,758
Commitments and contingencies
Stockholders' Equity    
Preferred stock - no shares issued or outstanding (no par value, 26 million shares authorized) $ 0 $ 0
Common stock issued - 937 million and 770 million shares (par value $1 per share, 1.1 billion shares authorized) 937 770
Common stock, securities exchangeable into common stock - no shares issued or outstanding (no par value, 29 million shares authorized) 0 0
Common stock, held in treasury, at cost - 89 million and 93 million shares (3,397) (3,554)
Additional paid-in capital 7,428 6,498
Retained earnings 14,533 14,974
Accumulated other comprehensive loss (150) (135)
Total stockholders' equity 19,351 18,553
Total liabilities and stockholders' equity $ 32,868 $ 32,311
v3.4.0.3
Consolidated Balance Sheets Parentheticals - USD ($)
shares in Millions, $ in Millions
Mar. 31, 2016
Dec. 31, 2015
Consolidated Balance Sheets Parenthetical [Abstract]    
Allowance for Doubtful Accounts Receivable, Current $ 4 $ 4
Less accumulated depreciation, depletion and amortization $ (22,763) $ (23,260)
Preferred stock, no par value $ 0 $ 0
Preferred stock shares authorized 26 26
Preferred stock shares issued 0 0
Preferred stock shares outstanding 0 0
Common stock, par value per share $ 1 $ 1
Common stock shares authorized 1,100 1,100
Common stock, shares issued 937 770
Common stock, securities exchangeable, no par value $ 0 $ 0
Common stock, securities exchangeable, shares authorized 29 29
Common stock, securities exchangeable, shares issued 0 0
Common stock, securities exchangeable, shares outstanding 0 0
Common stock, held in treasury, shares 89 93
v3.4.0.3
Consolidated Statements of Cash Flows - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Operating activities:    
Net income (loss) $ (407) $ (276)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:    
Deferred income taxes (320) (179)
Depreciation, depletion and amortization 609 821
Impairments 1 0
Pension and other postretirement benefits, net 14 (7)
Exploratory dry well costs and unproved property impairments 11 67
Net (gain) loss on disposal of assets 60 (1)
Equity method investments, net 30 3
Changes in:    
Current receivables, changes in 133 388
Inventories, changes in 7 (22)
Current accounts payable and accrued liabilities, changes in (121) (469)
All other operating, net 57 (16)
Net Cash Provided by (Used in) Continuing Operations 74 309
Investing activities:    
Additions to property, plant and equipment (454) (1,452)
Disposal of assets 17 2
Investments - return of capital 14 10
All other investing, net 2 (2)
Net Cash Provided by (Used in) Investing Activities, Continuing Operations (421) (1,442)
Financing activities:    
Proceeds from Issuance of Common Stock 1,232 0
Dividends paid (34) (142)
All other financing, net 0 4
Net Cash Provided by (Used in) Financing Activities, Continuing Operations 1,198 (138)
Effect of Exchange Rate on Cash and Cash Equivalents, Continuing Operations 0 (1)
Net increase (decrease) in cash and cash equivalents 851 (1,272)
Cash and cash equivalents at beginning of period 1,221 2,398
Cash and cash equivalents at end of period $ 2,072 $ 1,126
v3.4.0.3
Basis of Presentation
 3 Months Ended
Mar. 31, 2016
Accounting Policies [Abstract]  
Basis of Presentation [Text Block]
Basis of Presentation
These consolidated financial statements are unaudited; however, in the opinion of management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported.  All such adjustments are of a normal recurring nature unless disclosed otherwise.  These consolidated financial statements, including notes, have been prepared in accordance with the applicable rules of the SEC and do not include all of the information and disclosures required by U.S. GAAP for complete financial statements.
These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our 2015 Annual Report on Form 10-K.  The results of operations for the first quarter of 2016 are not necessarily indicative of the results to be expected for the full year.
v3.4.0.3
Accounting Standards
 3 Months Ended
Mar. 31, 2016
Accounting Standards Disclosure [Abstract]  
Accounting Standards [Text Block]
Accounting Standards
Not Yet Adopted
In March 2016, the FASB issued a new accounting standards update that changes several aspects of accounting for share-based payment transactions, including a requirement to recognize all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This standard is effective for us in the first quarter of 2017 and varying transition methods (modified retrospective, retrospective or prospective) should be applied to different provisions of the standard. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.
In February 2016, the FASB issued a new lease accounting standard, which requires lessees to recognize most leases, including operating leases, on the balance sheet as a right of use asset and lease liability. Short-term leases can continue being accounted for off balance sheet based on a policy election. This standard is effective for us in the first quarter of 2019 and should be applied using a modified retrospective approach at the beginning of the earliest period presented in the financial statements. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it may have on our consolidated results of operations, financial position or cash flows.
In January 2016, the FASB issued an accounting standards update that addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. This standard is effective for us in the first quarter of 2018. Early adoption is allowed for certain provisions. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In July 2015, the FASB issued an update that requires an entity to measure inventory at the lower of cost and net realizable value. This excludes inventory measured using LIFO or the retail inventory method. This standard is effective for us in the first quarter of 2017 and will be applied prospectively. Early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In August 2014, the FASB issued an update that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards.  This standard is effective for us for the annual period ending after December 15, 2016 and for annual periods and interim periods thereafter. Early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In May 2014, the FASB issued an update that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. Among other things, the standard requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for us in the first quarter of 2018 and should be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.
Recently Adopted
In May 2015, the FASB issued an update that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The amendment also removes certain disclosure requirements regarding all investments that are eligible to be measured using the net asset value per share practical expedient and only requires certain disclosures on those investments for which an entity elects to use the net asset value per share expedient. This standard is effective for us in the first quarter of 2016 and was applied on a retrospective basis. This standard only modifies disclosure requirements; as such, there was no impact on our consolidated results of operations, financial position or cash flows.
In February 2015, the FASB issued an amendment to the guidance for determining whether an entity is a variable interest entity ("VIE"). The standard does not add or remove any of the five characteristics that determine whether an entity is a VIE. However, it does change the manner in which a reporting entity assesses one of the characteristics. In particular, when decision-making over the entity’s most significant activities has been outsourced, the standard changes how a reporting entity assesses if the equity holders at risk lack decision making rights. This standard is effective for us in the first quarter of 2016. The adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.
v3.4.0.3
Variable Interest Entity
 3 Months Ended
Mar. 31, 2016
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]  
Variable Interest Entity [Text Block]
Variable Interest Entity
The owners of the Athabasca Oil Sands Project, in which we hold a 20% undivided interest, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton, Alberta, Canada.  Costs under this contract are accrued and recorded on a monthly basis, with current liabilities of $2 million recorded at March 31, 2016 and December 31, 2015.  This contract qualifies as a variable interest contractual arrangement, and the Corridor Pipeline qualifies as a VIE.  We hold a variable interest but are not the primary beneficiary because our shipments are only 20% of the total; therefore, the Corridor Pipeline is not consolidated by us.  Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was $472 million as of March 31, 2016.  The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term.
v3.4.0.3
Income per Common Share
 3 Months Ended
Mar. 31, 2016
Earnings Per Share [Abstract]  
Income per Common Share [Text Block]
Loss) per Common Share
Basic income (loss) per share is based on the weighted average number of common shares outstanding.  Diluted income per share assumes exercise of stock options, provided the effect is not antidilutive. The per share calculations below exclude 13 million stock options for the first three months of 2016 and 2015 that were antidilutive.
 
Three Months Ended March 31,
(In millions, except per share data)
2016
 
2015
Net income (loss)
$
(407
)
 
$
(276
)
 
 
 
 
Weighted average common shares outstanding
730

 
675

Weighted average common shares, diluted
730

 
675

Net income (loss) per share:
 
 
 
Basic
$
(0.56
)
 
$
(0.41
)
Diluted
$
(0.56
)
 
$
(0.41
)
v3.4.0.3
Dispositions
 3 Months Ended
Mar. 31, 2016
Discontinued Operations and Disposal Groups [Abstract]  
Dispositions [Text Block]
Dispositions
North America E&P Segment
In April 2016, we entered into agreements to sell our Wyoming upstream and midstream assets for proceeds of $870 million, before closing adjustments. The upstream properties are comprised mainly of waterflood developments in the Big Horn and Wind River basins. The midstream assets include the 570-mile Red Butte pipeline. We expect the transaction to close mid-year 2016.
In March and April 2016, we entered into separate agreements to sell our 10% working interest in the outside-operated Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Colorado, and certain undeveloped acreage in West Texas for a combined total of approximately $80 million, before closing adjustments. The transactions are expected to close mid-year 2016.
 
 
v3.4.0.3
Segment Information
 3 Months Ended
Mar. 31, 2016
Segment Reporting [Abstract]  
Segment Information [Text Block]
Segment Information
  We have three reportable operating segments. Each of these segments is organized and managed based upon both geographic location and the nature of the products and services it offers.
•
N.A. E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in North America;
•
Int'l E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.; and
•
Oil Sands Mining (“OSM”) – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”).  Segment income represents income which excludes certain items not allocated to segments, net of income taxes, attributable to the operating segments. A portion of our corporate and operations support general and administrative costs are not allocated to the operating segments. These unallocated costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Gains or losses on dispositions, certain impairments, change in tax expense associated with a tax rate change, unrealized gains or losses on commodity derivative instruments, or other items that affect comparability (as determined by the CODM) also are not allocated to operating segments.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2016
 
 
 
Not Allocated
 
 
(In millions)
N.A. E&P
 
Int'l E&P
 
OSM
 
to Segments
 
Total
Sales and other operating revenues
$
493

 
$
96

 
$
148

 
$
(23
)
(c) 
$
714

Marketing revenues
31

 
15

 
12

 
—

 
58

Total revenues
524

 
111

 
160

 
(23
)
 
772

Income from equity method investments
—

 
14

 
—

 
—

 
14

Net gain (loss) on disposal of assets and other income
1

 
6

 
—

 
(63
)
(d) 
(56
)
Less:
 
 
 
 
 
 
 
 
 
Production expenses
134

 
53

 
141

 
—

 
328

Marketing costs
32

 
14

 
12

 
—

 
58

Exploration expenses
18

 
6

 
—

 
—


24

Depreciation, depletion and amortization
487

 
50

 
60

 
12

 
609

Impairments
1

 
—

 
—

 
—

 
1

Other expenses (a)
118

 
16

 
7

 
119

(e) 
260

Taxes other than income
42

 
—

 
5

 
1

 
48

Net interest and other
—

 
—

 
—

 
85

 
85

Income tax benefit
(112
)
 
(12
)
 
(17
)
 
(135
)
 
(276
)
Segment income (loss) / Net income (loss)
$
(195
)
 
$
4

 
$
(48
)
 
$
(168
)
 
$
(407
)
Capital expenditures (b)
$
315

 
$
32

 
$
9

 
$
3

 
$
359


(a) 
Includes other operating expenses and general and administrative expenses.
(b)Includes accruals.
(c) 
Unrealized loss on commodity derivative instruments.
(d) 
Related to the net loss on disposal of assets (see Note 5).
(e) 
Includes pension settlement loss of $48 million and severance related expenses associated with workforce reductions of $7 million (see Note 7).
 
Three Months Ended March 31, 2015
 
 
 
Not Allocated
 
 
(In millions)
N.A. E&P
 
Int'l E&P
 
OSM
 
to Segments
 
Total
Sales and other operating revenues
$
850

 
$
182

 
$
225

 
$
23

(c) 
$
1,280

Marketing revenues
178

 
26

 
—

 
—

 
204

Total revenues
1,028

 
208

 
225

 
23

 
1,484

Income from equity method investments
—

 
36

 
—

 
—

 
36

Net gain on disposal of assets and other income
—

 
10

 
1

 
1

 
12

Less:
 
 
 
 
 
 
 
 
 
Production expenses
202

 
67

 
175

 
—

 
444

Marketing costs
180

 
25

 
—

 
—

 
205

Exploration expenses
35

 
55

 
—

 
—

 
90

Depreciation, depletion and amortization
683

 
64

 
62

 
12

 
821

Other expenses (a)
117

 
23

 
9

 
129

(d) 
278

Taxes other than income
61

 
—

 
5

 
1

 
67

Net interest and other
—

 
—

 
—

 
47

 
47

Income tax benefit
(89
)
 
(3
)
 
(6
)
 
(46
)
 
(144
)
Segment income (loss) / Net income (loss)
$
(161
)
 
$
23

 
$
(19
)
 
$
(119
)
 
$
(276
)
Capital expenditures (b)
$
933

 
$
146

 
$
21

 
$
2

 
$
1,102


(a) 
Includes other operating expenses and general and administrative expenses.
(b) 
Includes accruals.
(c) 
Unrealized gain on commodity derivative instruments.
(d) 
Includes $43 million of severance related expenses associated with a workforce reduction and pension settlement loss of $17 million (see Note 7).
v3.4.0.3
Defined Benefit Postretirement Plans
 3 Months Ended
Mar. 31, 2016
Defined Benefit Postretirement Plans Disclosure [Abstract]  
Defined Benefit Postretirement Plans [Text Block]
Defined Benefit Postretirement Plans
The following summarizes the components of net periodic benefit cost:
 
 
 
 
 
 
 
 
 
Three Months Ended March 31,
  
Pension Benefits
 
Other Benefits
(In millions)
2016
 
2015
 
2016
 
2015
Service cost
$
6

 
$
12

 
$
1

 
$
1

Interest cost
11

 
14

 
3

 
3

Expected return on plan assets
(15
)
 
(19
)
 
—

 
—

Amortization:
 
 
 

 
 

 
 

– prior service cost (credit)
(2
)
 
1

 
(1
)
 
(1
)
– actuarial loss
3

 
7

 
—

 
—

Net settlement loss(a)
48

 
17

 
—

 
—

Net curtailment loss (gain) (b)
—

 
1

 
—

 
(6
)
Net periodic benefit cost
$
51


$
33


$
3


$
(3
)

(a) 
Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan's total service and interest cost for that year.
(b) 
Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans.
During the first three months of 2016, we recorded the effects of settlements of our U.S. pension plans. As required, we remeasured the plans' assets and liabilities as of the applicable balance sheet dates. The cumulative effects of these events are included in the remeasurement and reflected in both the pension liability and net periodic benefit cost.
During the first three months of 2016, we made contributions of $14 million to our funded pension plans.  We expect to make additional contributions up to an estimated $48 million to our funded pension plans over the remainder of 2016.  During the first three months of 2016, we made payments of $19 million and $5 million related to unfunded pension plans and other postretirement benefit plans, respectively.
v3.4.0.3
Income Taxes
 3 Months Ended
Mar. 31, 2016
Income Tax Disclosure [Abstract]  
Income Taxes
Income Taxes
Effective Tax Rate
The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The difference between the total provision and the sum of the amounts allocated to segments is reported in the “Not Allocated to Segments” column of the tables in Note 6.
Our effective income tax rates for the first three months of 2016 and 2015 were 40% and 34%.  In Libya, uncertainty remains around the timing of future production and sales levels. Reliable estimates of 2016 and 2015 Libyan annual ordinary income from our operations could not be made and the range of possible scenarios in the worldwide annual effective tax rate calculation demonstrates significant variability. Thus, the tax benefit applicable to Libyan ordinary loss was recorded as a discrete item in the first three months of 2016 and 2015.  For the first three months of 2016 and 2015, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss). Excluding Libya, the effective tax rates, would be 39% and 31% for the first three months of 2016 and 2015. The change was driven by a shift in jurisdictional income.
Deferred Tax Assets
In connection with our assessment of the realizability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of our deferred tax assets will not be realized.  In the event it is more likely than not that some portion or all of our deferred taxes will not be realized, such assets are reduced by a valuation allowance. Future increases to our valuation allowance are possible if our estimates and assumptions (particularly as they relate to downward revisions of our long-term commodity price forecast) are revised such that they reduce estimates of future taxable income during the carryforward period.
v3.4.0.3
Inventories
 3 Months Ended
Mar. 31, 2016
Inventory Disclosure [Abstract]  
Inventories [Text Block]
Inventories
 Liquid hydrocarbons, natural gas and bitumen are recorded at weighted average cost and carried at the lower of cost or market value. Supplies and other items consist principally of tubular goods and equipment which are valued at weighted average cost and reviewed periodically for obsolescence or impairment when market conditions indicate.
 
March 31,
 
December 31,
(In millions)
2016
 
2015
Liquid hydrocarbons, natural gas and bitumen
$
33

 
$
35

Supplies and other items
273

 
278

Inventories, at cost
$
306

 
$
313
v3.4.0.3
Property, Plant and Equipment
 3 Months Ended
Mar. 31, 2016
Property, Plant and Equipment [Abstract]  
Property, Plant and Equipment [Text Block]
 Property, Plant and Equipment, net of Accumulated Depreciation, Depletion and Amortization
 
March 31,
 
December 31,
(In millions)
2016
 
2015
North America E&P
$
14,953

 
$
15,226

International E&P
2,521

 
2,533

Oil Sands Mining
9,148

 
9,197

Corporate
115

 
105

Net property, plant and equipment
$
26,737


$
27,061


Our Libya operations continue to be impacted by civil unrest. Operations were interrupted in mid-2013 as a result of the shutdown of the Es Sider crude oil terminal, and although temporarily re-opened during the second half of 2014, production remains shut-in. Considerable uncertainty remains around the timing of future production and sales levels.
As of March 31, 2016, our net property, plant and equipment investment in Libya is $776 million, and total proved reserves (unaudited) in Libya as of December 31, 2015 are 235 million barrels of oil equivalent ("mmboe"). We and our partners in the Waha concessions continue to assess the situation and the condition of our assets in Libya. Our periodic assessment of the carrying value of our net property, plant and equipment in Libya specifically considers the net investment in the assets, the duration of our concessions and the reserves anticipated to be recoverable in future periods. The undiscounted cash flows related to our Libya assets continue to exceed the carrying value of $776 million by a material amount.
Exploratory well costs capitalized greater than one year after completion of drilling were $120 million and $85 million as of March 31, 2016 and December 31, 2015. The $35 million increase primarily relates to the Alba Block Sub Area B offshore Equatorial Guinea where the Rodo well reached total depth in the first quarter of 2015. We have since completed a seismic feasibility study and continue to finalize next steps in the Alba Block Sub Area B exploration program.
v3.4.0.3
Fair Value Measurements
 3 Months Ended
Mar. 31, 2016
Fair Value Disclosures [Abstract]  
Fair Value Measurements [Text Block]
Fair Value Measurements
 Fair Values - Recurring
The following tables present assets and liabilities accounted for at fair value on a recurring basis as of March 31, 2016 and December 31, 2015 by fair value hierarchy level.
 
March 31, 2016
(In millions)
Level 1
 
Level 2
 
Level 3
 
Total
Derivative instruments, assets
 
 
 
 
 
 
 
     Commodity (a)
$
—

 
$
51

 
$
—

 
$
51

     Interest rate
—

 
12

 
—

 
12

Derivative instruments, assets
$
—

 
$
63

 
$
—

 
$
63

Derivative instruments, liabilities
 
 
 
 
 
 
 
     Commodity (a)
$
—

 
$
24

 
$
—

 
$
24

Derivative instruments, liabilities
$
—

 
$
24

 
$
—

 
$
24


(a)  
Derivative instruments are recorded on a net basis in the company's balance sheet (see Note 12).
 
December 31, 2015
(In millions)
Level 1
 
Level 2
 
Level 3
 
Total
Derivative instruments, assets
 
 
 
 
 
 
 
     Commodity (a)
$
—

 
$
51

 
$
—

 
$
51

Interest rate
$
—

 
$
8

 
$
—

 
$
8

Derivative instruments, assets
$
—

 
$
59

 
$
—

 
$
59

Derivative instruments, liabilities
 
 
 
 
 
 
 
     Commodity (a)
$
—

 
$
1

 
$
—

 
$
1

Derivative instruments, liabilities
$
—

 
$
1

 
$
—

 
$
1


(a)  
Derivative instruments are recorded on a net basis in the company's balance sheet (see Note 12).
Commodity derivatives include three-way collars, extendable three-way collars, call options, swaps and swaptions. These instruments are measured at fair value using either the Black-Scholes Model or the Black Model. Inputs to both models include prices, interest rates, and implied volatility. The inputs to these models are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.
Interest rate swaps are measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs. See Note 12 for additional discussion of the types of derivative instruments we use.
Fair Values – Goodwill
Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. We estimate the fair value of our International E&P reporting unit using a combination of market and income approaches. The market approach referenced observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value, and valuation multiples of us and our peers for the investor analyst community. The income approach utilized discounted cash flows, which were based on forecasted assumptions. Key assumptions to the income approach include future liquid hydrocarbon and natural gas pricing, estimated quantities of liquid hydrocarbons and natural gas proved and probable reserves, estimated timing of production, discount rates, future capital requirements and operating expenses and tax rates. The assumptions used in the income approach are consistent with those that management uses to make business decisions. These valuations methodologies represent Level 3 fair value measurements. A triggering event related to price declines in our common stock required us to reassess our goodwill for impairment as of March 31, 2016. Based on the results of this assessment, we concluded no impairment was required. While the fair value of our International E&P reporting unit exceeded book value, subsequent commodity price and/or common stock declines may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.
Fair Values – Financial Instruments
Our current assets and liabilities include financial instruments, the most significant of which are receivables, long-term debt and payables. We believe the carrying values of our receivables and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our credit rating, and (3) our historical incurrence of and expected future insignificant bad debt expense, which includes an evaluation of counterparty credit risk.
The following table summarizes financial instruments, excluding receivables, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at March 31, 2016 and December 31, 2015.
 
March 31, 2016
 
December 31, 2015
 
Fair
 
Carrying
 
Fair
 
Carrying
(In millions)
Value
 
Amount
 
Value
 
Amount
Financial assets
 
 
 
 
 
 
 
Other noncurrent assets
$
115

 
$
120

 
$
104

 
$
118

Total financial assets  
$
115

 
$
120

 
$
104

 
$
118

Financial liabilities
 

 
 

 
 

 
 

     Other current liabilities
$
34

 
$
33

 
$
34

 
$
33

     Long-term debt, including current portion (a)
6,575

 
7,291

 
6,723

 
7,291

Deferred credits and other liabilities
104

 
105

 
97

 
95

Total financial liabilities  
$
6,713

 
$
7,429

 
$
6,854

 
$
7,419

(a)    Excludes capital leases, debt issuance costs and interest rate swap adjustments.
Fair values of our financial assets included in other noncurrent assets, and of our financial liabilities included in other current liabilities and deferred credits and other liabilities, are measured using an income approach and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value.
Most of our long-term debt instruments are publicly-traded. A market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is used to measure the fair value of such debt. The fair value of our debt that is not publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.
v3.4.0.3
Derivatives
 3 Months Ended
Mar. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivatives [Text Block]
Derivatives
For further information regarding the fair value measurement of derivative instruments, see Note 11. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts where they appear on the consolidated balance sheets.
 
March 31, 2016
 
 
(In millions)
Asset
 
Liability
 
Net Asset
 
Balance Sheet Location
Fair Value Hedges
 
 
 
 
 
 
 
     Interest rate
$
12

 
$
—

 
$
12

 
Other noncurrent assets
Total Designated Hedges
$
12

 
$
—

 
$
12

 
 
 
 
 
 
 
 
 
 
Not Designated as Hedges
 
 
 
 
 
 
 
     Commodity
$
51

 
$
7

 
$
44

 
Other current assets
Total Not Designated as Hedges
$
51

 
$
7

 
$
44

 
 
     Total
$
63


$
7


$
56

 
 
 
 
 
 
 
 
 
 
 
March 31, 2016
 
 
(In millions)
Asset
 
Liability
 
Net Liability
 
Balance Sheet Location
Not Designated as Hedges
 
 
 
 
 
 
 
     Commodity
$
—

 
$
17

 
$
17

 
Deferred credits and other liabilities
Total Not Designated as Hedges
$
—

 
$
17

 
$
17

 
 
     Total
$
—

 
$
17

 
$
17

 
 
 
 
 
 
 
 
 
 

 
December 31, 2015
 
 
(In millions)
Asset
 
Liability
 
Net Asset
 
Balance Sheet Location
Fair Value Hedges
 
 
 
 
 
 
 
     Interest rate
$
8

 
$
—

 
$
8

 
Other noncurrent assets
Total Designated Hedges
$
8

 
$
—

 
$
8

 
 
 
 
 
 
 
 
 
 
Not Designated as Hedges
 
 
 
 
 
 
 
     Commodity
$
51

 
$
1

 
$
50

 
Other current assets
Total Not Designated as Hedges
$
51

 
$
1

 
$
50

 
 
     Total
$
59

 
$
1

 
$
58

 
 

Derivatives Designated as Fair Value Hedges
The following table presents, by maturity date, information about our interest rate swap agreements, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.
 
March 31, 2016
 
December 31, 2015
 
Aggregate Notional Amount
Weighted Average, LIBOR-Based,
 
Aggregate Notional Amount
Weighted Average, LIBOR-Based,
Maturity Dates
(in millions)
Floating Rate
 
(in millions)
Floating Rate
October 1, 2017
$
600

4.92
%
 
$
600

4.73
%
March 15, 2018
$
300

4.77
%
 
$
300

4.66
%

The pretax effects of derivative instruments designated as hedges of fair value in our consolidated statements of income are summarized in the table below. There is no ineffectiveness related to fair value hedges.
 
 
Gain (Loss)
 
 
 
Three Months Ended March 31,
(In millions)
Income Statement Location
 
2016
 
2015
Derivative
 
 
 
 
 
Interest rate
Net interest and other
 
$
4

 
$
5

Hedged Item
 
 
 

 
 

Long-term debt
Net interest and other
 
$
(4
)
 
$
(5
)

 Derivatives not Designated as Hedges
During 2015 and the first quarter of 2016, we entered into multiple crude oil and natural gas derivatives indexed to NYMEX WTI and Henry Hub related to a portion of our forecasted North America E&P sales through December 2017. These commodity derivatives consist of three-way collars, extendable three-way collars, call options, swaps, and swaptions. Three-way collars consist of a sold call (ceiling), a purchased put (floor) and a sold put. The ceiling price is the maximum we will receive for the contract volumes, the floor is the minimum price we will receive, unless the market price falls below the sold put strike price. In this case, we receive the NYMEX WTI/Henry Hub price plus the difference between the floor and the sold put price. These commodity derivatives were not designated as hedges. The following table sets forth outstanding derivative contracts as of March 31, 2016 and the weighted average prices for those contracts:
Crude Oil (a)
 
2016
Year Ending December 31,
 
Second Quarter
Third Quarter
Fourth Quarter
2017
Three-Way Collars (b)
Volume (Bbls/day)
39,000
37,000
37,000
—
Price per Bbl:
 
 
 
 
Ceiling
$55.47
$54.52
$54.52
—
Floor
$51.56
$50.83
$50.83
—
Sold put
$41.67
$41.22
$41.22
—
Options (c)
 
 
 
 
Volume (Bbls/day)
10,000
10,000
10,000
25,000
Price per Bbl
$72.39
$72.39
$72.39
$60.67
Swaps
 
 
 
 
Volume (Bbls/day)
25,000
—
—
—
Price per Bbl
$39.25
—
—
—

(a) Subsequent to March 31, 2016, we entered into 10,000 Bbls/day of two-way collars for July - December 2016 with a ceiling price of $50.00 and a floor price of $41.55. We also entered into 10,000 Bbls/day of 2016 three-way collars for May - December 2016 with a ceiling price of $58.51, a floor price of $48.00, and a sold put price of $40.00, traded in conjunction with sold call options of 10,000 Bbls/day for 2017 at $65.00.
(b) 
A counterparty has the option, exercisable on June 30, 2016, to extend three-way collars for 2,000 Bbls/day through the remainder of 2016 at a ceiling of $73.13, floor of $65.00 and sold put of $50.00.
(c) 
Call options settle monthly.
Natural Gas (a)
 
2016
Year Ending December 31,
 
Second Quarter
Third Quarter
Fourth Quarter
2017
Three-Way Collars (b)
 
 
 
 
Volume (MMBtu/day)
20,000
20,000
20,000
20,000
Price per MMBtu
 
 
 
 
Ceiling
$2.93
$2.93
$2.93
$3.07
Floor
$2.50
$2.50
$2.50
$2.75
Sold put
$2.00
$2.00
$2.00
$2.25
(a) 
Subsequent to March 31, 2016, we entered into 20,000 MMBtu/day of 2017 three-way collars with a ceiling price of $3.50, a floor price of $2.75, and a sold put price of $2.25.
(b) 
Counterparty has the option to execute fixed-price swaps (swaptions) at a weighted average price of $2.93 per MMBtu indexed to NYMEX Henry Hub, which is exercisable on December 22, 2016. If counterparty exercises, the term of the fixed-price swaps would be for the calendar year 2017 and, if all such options are exercised, 20,000 MMBtu per day.
The impact of these commodity derivative instruments appears in sales and other operating revenues in our consolidated statements of income and was a net loss of $2 million and net gain of $26 million in the first quarters of 2016 and 2015, respectively.
v3.4.0.3
Incentive Based Compensation
 3 Months Ended
Mar. 31, 2016
Incentive Based Compensation Plans [Abstract]  
Incentive Based Compensation [Text Block]
Incentive Based Compensation
 Stock options, restricted stock awards and restricted stock units
The following table presents a summary of activity for the first three months of 2016: 
 
Stock Options
 
Restricted Stock Awards & Units
 
Number of
Shares
 
Weighted
Average
Exercise Price
 
Awards
 
Weighted
Average Grant
Date Fair Value
Outstanding at December 31, 2015
12,665,419

 

$29.97

 
4,017,344

 

$30.76

Granted
1,680,000

(a) 

$7.22

 
5,230,708

 

$7.91

Options Exercised/Stock Vested
—

 
—

 
(44,096
)
 

$32.01

Canceled
(181,681
)
 

$29.69

 
(220,614
)
 

$30.00

Outstanding at March 31, 2016
14,163,738

 

$27.27

 
8,983,342

 

$17.47

(a)    The weighted average grant date fair value of stock option awards granted was $1.97 per share.
Stock-based performance unit awards
 During the first three months of 2016, we granted 1,205,517 stock-based performance units to certain officers. The grant date fair value per unit was $3.72.
v3.4.0.3
Debt (Notes)
 3 Months Ended
Mar. 31, 2016
Debt Disclosure [Abstract]  
Debt
Debt
Revolving Credit Facility
As of March 31, 2016, we had no borrowings against our revolving credit facility (the "Credit Facility"), as described below.
In March 2016, we increased our $3.0 billion unsecured Credit Facility by $300 million to a total of $3.3 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the increase.
The Credit Facility includes a covenant requiring that our ratio of total debt to total capitalization not exceed 65% as of the last day of each fiscal quarter. If an event of default occurs, the lenders holding more than half of the commitments may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility. As of March 31, 2016, we were in compliance with this covenant with a debt-to-capitalization ratio of 27%.
v3.4.0.3
Reclassifications out of Accumulated Other Comprehensive Income
 3 Months Ended
Mar. 31, 2016
Reclassifications out of AccumulatedOtherComprehensiveIncome [Abstract]  
Reclassifications Out of Accumulated Other Comprehensive Loss
Reclassifications Out of Accumulated Other Comprehensive Loss
The following table presents a summary of amounts reclassified from accumulated other comprehensive loss:
 
Three Months Ended March 31,
 
 
(In millions)
2016
 
2015
 
Income Statement Line
 
 
 
 
Postretirement and postemployment plans
 
 
 
 
 
Amortization of actuarial loss
$
(3
)
 
$
(7
)
 
General and administrative
Net settlement loss
(48
)
 
(17
)
 
General and administrative
Net curtailment gain (loss)
—

 
5

 
General and administrative
 
(51
)
 
(19
)
 
Income (loss) from operations
 
19

 
7

 
Provision (benefit) for income taxes
Total reclassifications to expense
$
(32
)
 
$
(12
)
 
Net income (loss)
v3.4.0.3
Stockholders' Equity (Notes)
 3 Months Ended
Mar. 31, 2016
Stockholders' Equity Attributable to Parent [Abstract]  
Stockholders' Equity Note Disclosure [Text Block]
Stockholder's Equity
In March 2016, we issued 166,750,000 shares of our common stock, par value $1 per share, at a price of $7.65 per share, excluding underwriting discounts and commissions, for net proceeds of $1,232 million. The proceeds will be used to strengthen our balance sheet and for general corporate purposes, including funding a portion of our Capital Program.
v3.4.0.3
Supplemental Cash Flow Information
 3 Months Ended
Mar. 31, 2016
Supplemental Cash Flow Information [Abstract]  
Supplemental Cash Flow Information [Text Block]
Supplemental Cash Flow Information
 
Three Months Ended March 31,
(In millions)
2016
 
2015
Net cash (used in) operating activities:
 
 
 
Interest paid (net of amounts capitalized)
$
(87
)
 
$
(55
)
Income taxes paid to taxing authorities
(15
)
 
(47
)
Noncash investing activities:
 

 
 

Asset retirement cost increase
$
2

 
$
21

Asset retirement obligations assumed by buyer
54

 
—
v3.4.0.3
Commitments and Contingencies
 3 Months Ended
Mar. 31, 2016
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies
Commitments and Contingencies
  We are a defendant in a number of legal and administrative proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims, tax disputes and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.
v3.4.0.3
Subsequent Events (Notes)
 3 Months Ended
Mar. 31, 2016
Subsequent Events [Abstract]  
Subsequent Events [Text Block]
Subsequent Event
In September 2015, we announced our intention to scale back our conventional exploration program, with future exploration investment focused on fulfilling our existing commitments in the Gulf of Mexico and Gabon. In April 2016, we made the decision not to drill any of our remaining Gulf of Mexico undeveloped leases. As a result, we expect to record a non-cash impairment between $140 million and $150 million in the second quarter of 2016. We retain our existing deepwater drilling rig commitment, in which we have approximately 200 days of contract term remaining.
v3.4.0.3
Basis of Presentation Accounting Policy (Policies)
 3 Months Ended
Mar. 31, 2016
Accounting Policies [Abstract]  
Basis of Accounting, Policy [Policy Text Block]
These consolidated financial statements are unaudited; however, in the opinion of management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported.  All such adjustments are of a normal recurring nature unless disclosed otherwise.  These consolidated financial statements, including notes, have been prepared in accordance with the applicable rules of the SEC and do not include all of the information and disclosures required by U.S. GAAP for complete financial statements.
These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our 2015 Annual Report on Form 10-K.  The results of operations for the first quarter of 2016 are not necessarily indicative of the results to be expected for the full year.
v3.4.0.3
Income per Common Share (Tables)
 3 Months Ended
Mar. 31, 2016
Earnings Per Share [Abstract]  
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]
The per share calculations below exclude 13 million stock options for the first three months of 2016 and 2015 that were antidilutive.
 
Three Months Ended March 31,
(In millions, except per share data)
2016
 
2015
Net income (loss)
$
(407
)
 
$
(276
)
 
 
 
 
Weighted average common shares outstanding
730

 
675

Weighted average common shares, diluted
730

 
675

Net income (loss) per share:
 
 
 
Basic
$
(0.56
)
 
$
(0.41
)
Diluted
$
(0.56
)
 
$
(0.41
)
v3.4.0.3
Segment Information (Tables)
 3 Months Ended
Mar. 31, 2016
Segment Reporting [Abstract]  
Schedule of Segment Reporting Information, by Segment [Table Text Block]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2016
 
 
 
Not Allocated
 
 
(In millions)
N.A. E&P
 
Int'l E&P
 
OSM
 
to Segments
 
Total
Sales and other operating revenues
$
493

 
$
96

 
$
148

 
$
(23
)
(c) 
$
714

Marketing revenues
31

 
15

 
12

 
—

 
58

Total revenues
524

 
111

 
160

 
(23
)
 
772

Income from equity method investments
—

 
14

 
—

 
—

 
14

Net gain (loss) on disposal of assets and other income
1

 
6

 
—

 
(63
)
(d) 
(56
)
Less:
 
 
 
 
 
 
 
 
 
Production expenses
134

 
53

 
141

 
—

 
328

Marketing costs
32

 
14

 
12

 
—

 
58

Exploration expenses
18

 
6

 
—

 
—


24

Depreciation, depletion and amortization
487

 
50

 
60

 
12

 
609

Impairments
1

 
—

 
—

 
—

 
1

Other expenses (a)
118

 
16

 
7

 
119

(e) 
260

Taxes other than income
42

 
—

 
5

 
1

 
48

Net interest and other
—

 
—

 
—

 
85

 
85

Income tax benefit
(112
)
 
(12
)
 
(17
)
 
(135
)
 
(276
)
Segment income (loss) / Net income (loss)
$
(195
)
 
$
4

 
$
(48
)
 
$
(168
)
 
$
(407
)
Capital expenditures (b)
$
315

 
$
32

 
$
9

 
$
3

 
$
359


(a) 
Includes other operating expenses and general and administrative expenses.
(b)Includes accruals.
(c) 
Unrealized loss on commodity derivative instruments.
(d) 
Related to the net loss on disposal of assets (see Note 5).
(e) 
Includes pension settlement loss of $48 million and severance related expenses associated with workforce reductions of $7 million (see Note 7).
 
Three Months Ended March 31, 2015
 
 
 
Not Allocated
 
 
(In millions)
N.A. E&P
 
Int'l E&P
 
OSM
 
to Segments
 
Total
Sales and other operating revenues
$
850

 
$
182

 
$
225

 
$
23

(c) 
$
1,280

Marketing revenues
178

 
26

 
—

 
—

 
204

Total revenues
1,028

 
208

 
225

 
23

 
1,484

Income from equity method investments
—

 
36

 
—

 
—

 
36

Net gain on disposal of assets and other income
—

 
10

 
1

 
1

 
12

Less:
 
 
 
 
 
 
 
 
 
Production expenses
202

 
67

 
175

 
—

 
444

Marketing costs
180

 
25

 
—

 
—

 
205

Exploration expenses
35

 
55

 
—

 
—

 
90

Depreciation, depletion and amortization
683

 
64

 
62

 
12

 
821

Other expenses (a)
117

 
23

 
9

 
129

(d) 
278

Taxes other than income
61

 
—

 
5

 
1

 
67

Net interest and other
—

 
—

 
—

 
47

 
47

Income tax benefit
(89
)
 
(3
)
 
(6
)
 
(46
)
 
(144
)
Segment income (loss) / Net income (loss)
$
(161
)
 
$
23

 
$
(19
)
 
$
(119
)
 
$
(276
)
Capital expenditures (b)
$
933

 
$
146

 
$
21

 
$
2

 
$
1,102


(a) 
Includes other operating expenses and general and administrative expenses.
(b) 
Includes accruals.
(c) 
Unrealized gain on commodity derivative instruments.
(d) 
Includes $43 million of severance related expenses associated with a workforce reduction and pension settlement loss of $17 million (see Note 7).
v3.4.0.3
Defined Benefit Postretirement Plans (Tables)
 3 Months Ended
Mar. 31, 2016
Defined Benefit Postretirement Plans Disclosure [Abstract]  
Schedule of Defined Benefit Plans Disclosures [Table Text Block]
The following summarizes the components of net periodic benefit cost:
 
 
 
 
 
 
 
 
 
Three Months Ended March 31,
  
Pension Benefits
 
Other Benefits
(In millions)
2016
 
2015
 
2016
 
2015
Service cost
$
6

 
$
12

 
$
1

 
$
1

Interest cost
11

 
14

 
3

 
3

Expected return on plan assets
(15
)
 
(19
)
 
—

 
—

Amortization:
 
 
 

 
 

 
 

– prior service cost (credit)
(2
)
 
1

 
(1
)
 
(1
)
– actuarial loss
3

 
7

 
—

 
—

Net settlement loss(a)
48

 
17

 
—

 
—

Net curtailment loss (gain) (b)
—

 
1

 
—

 
(6
)
Net periodic benefit cost
$
51


$
33


$
3


$
(3
)

(a) 
Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan's total service and interest cost for that year.
(b) 
Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans
v3.4.0.3
Inventories (Tables)
 3 Months Ended
Mar. 31, 2016
Inventory Disclosure [Abstract]  
Schedule of Inventory, Current [Table Text Block]
 
March 31,
 
December 31,
(In millions)
2016
 
2015
Liquid hydrocarbons, natural gas and bitumen
$
33

 
$
35

Supplies and other items
273

 
278

Inventories, at cost
$
306

 
$
313
v3.4.0.3
Property, Plant and Equipment (Tables)
 3 Months Ended
Mar. 31, 2016
Property, Plant and Equipment [Abstract]  
Schedule Of Property Plant And Equipment [Table Text Block]
 
March 31,
 
December 31,
(In millions)
2016
 
2015
North America E&P
$
14,953

 
$
15,226

International E&P
2,521

 
2,533

Oil Sands Mining
9,148

 
9,197

Corporate
115

 
105

Net property, plant and equipment
$
26,737


$
27,061
v3.4.0.3
Fair Value Measurements (Tables)
 3 Months Ended
Mar. 31, 2016
Fair Value Disclosures [Abstract]  
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]
The following tables present assets and liabilities accounted for at fair value on a recurring basis as of March 31, 2016 and December 31, 2015 by fair value hierarchy level.
 
March 31, 2016
(In millions)
Level 1
 
Level 2
 
Level 3
 
Total
Derivative instruments, assets
 
 
 
 
 
 
 
     Commodity (a)
$
—

 
$
51

 
$
—

 
$
51

     Interest rate
—

 
12

 
—

 
12

Derivative instruments, assets
$
—

 
$
63

 
$
—

 
$
63

Derivative instruments, liabilities
 
 
 
 
 
 
 
     Commodity (a)
$
—

 
$
24

 
$
—

 
$
24

Derivative instruments, liabilities
$
—

 
$
24

 
$
—

 
$
24


(a)  
Derivative instruments are recorded on a net basis in the company's balance sheet (see Note 12).
 
December 31, 2015
(In millions)
Level 1
 
Level 2
 
Level 3
 
Total
Derivative instruments, assets
 
 
 
 
 
 
 
     Commodity (a)
$
—

 
$
51

 
$
—

 
$
51

Interest rate
$
—

 
$
8

 
$
—

 
$
8

Derivative instruments, assets
$
—

 
$
59

 
$
—

 
$
59

Derivative instruments, liabilities
 
 
 
 
 
 
 
     Commodity (a)
$
—

 
$
1

 
$
—

 
$
1

Derivative instruments, liabilities
$
—

 
$
1

 
$
—

 
$
1
Fair Value, by Balance Sheet Grouping [Table Text Block]
The following table summarizes financial instruments, excluding receivables, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at March 31, 2016 and December 31, 2015.
 
March 31, 2016
 
December 31, 2015
 
Fair
 
Carrying
 
Fair
 
Carrying
(In millions)
Value
 
Amount
 
Value
 
Amount
Financial assets
 
 
 
 
 
 
 
Other noncurrent assets
$
115

 
$
120

 
$
104

 
$
118

Total financial assets  
$
115

 
$
120

 
$
104

 
$
118

Financial liabilities
 

 
 

 
 

 
 

     Other current liabilities
$
34

 
$
33

 
$
34

 
$
33

     Long-term debt, including current portion (a)
6,575

 
7,291

 
6,723

 
7,291

Deferred credits and other liabilities
104

 
105

 
97

 
95

Total financial liabilities  
$
6,713

 
$
7,429

 
$
6,854

 
$
7,419

(a)    Excludes capital leases, debt issuance costs and interest rate swap adjustments.
v3.4.0.3
Derivatives (Tables)
 3 Months Ended
Mar. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivatives as they appear on the balance sheet [Table Text Block]
The following tables present the gross fair values of derivative instruments and the reported net amounts where they appear on the consolidated balance sheets.
 
March 31, 2016
 
 
(In millions)
Asset
 
Liability
 
Net Asset
 
Balance Sheet Location
Fair Value Hedges
 
 
 
 
 
 
 
     Interest rate
$
12

 
$
—

 
$
12

 
Other noncurrent assets
Total Designated Hedges
$
12

 
$
—

 
$
12

 
 
 
 
 
 
 
 
 
 
Not Designated as Hedges
 
 
 
 
 
 
 
     Commodity
$
51

 
$
7

 
$
44

 
Other current assets
Total Not Designated as Hedges
$
51

 
$
7

 
$
44

 
 
     Total
$
63


$
7


$
56

 
 
 
 
 
 
 
 
 
 
 
March 31, 2016
 
 
(In millions)
Asset
 
Liability
 
Net Liability
 
Balance Sheet Location
Not Designated as Hedges
 
 
 
 
 
 
 
     Commodity
$
—

 
$
17

 
$
17

 
Deferred credits and other liabilities
Total Not Designated as Hedges
$
—

 
$
17

 
$
17

 
 
     Total
$
—

 
$
17

 
$
17

 
 
 
 
 
 
 
 
 
 

 
December 31, 2015
 
 
(In millions)
Asset
 
Liability
 
Net Asset
 
Balance Sheet Location
Fair Value Hedges
 
 
 
 
 
 
 
     Interest rate
$
8

 
$
—

 
$
8

 
Other noncurrent assets
Total Designated Hedges
$
8

 
$
—

 
$
8

 
 
 
 
 
 
 
 
 
 
Not Designated as Hedges
 
 
 
 
 
 
 
     Commodity
$
51

 
$
1

 
$
50

 
Other current assets
Total Not Designated as Hedges
$
51

 
$
1

 
$
50

 
 
     Total
$
59

 
$
1

 
$
58

 
 
Schedule of Interest Rate Derivatives [Table Text Block]
The following table presents, by maturity date, information about our interest rate swap agreements, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.
 
March 31, 2016
 
December 31, 2015
 
Aggregate Notional Amount
Weighted Average, LIBOR-Based,
 
Aggregate Notional Amount
Weighted Average, LIBOR-Based,
Maturity Dates
(in millions)
Floating Rate
 
(in millions)
Floating Rate
October 1, 2017
$
600

4.92
%
 
$
600

4.73
%
March 15, 2018
$
300

4.77
%
 
$
300

4.66
%
Effects of derivatives designated as fair value hedges [Table Text Block]
 
 
Gain (Loss)
 
 
 
Three Months Ended March 31,
(In millions)
Income Statement Location
 
2016
 
2015
Derivative
 
 
 
 
 
Interest rate
Net interest and other
 
$
4

 
$
5

Hedged Item
 
 
 

 
 

Long-term debt
Net interest and other
 
$
(4
)
 
$
(5
)
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]
These commodity derivatives were not designated as hedges. The following table sets forth outstanding derivative contracts as of March 31, 2016 and the weighted average prices for those contracts:
Crude Oil (a)
 
2016
Year Ending December 31,
 
Second Quarter
Third Quarter
Fourth Quarter
2017
Three-Way Collars (b)
Volume (Bbls/day)
39,000
37,000
37,000
—
Price per Bbl:
 
 
 
 
Ceiling
$55.47
$54.52
$54.52
—
Floor
$51.56
$50.83
$50.83
—
Sold put
$41.67
$41.22
$41.22
—
Options (c)
 
 
 
 
Volume (Bbls/day)
10,000
10,000
10,000
25,000
Price per Bbl
$72.39
$72.39
$72.39
$60.67
Swaps
 
 
 
 
Volume (Bbls/day)
25,000
—
—
—
Price per Bbl
$39.25
—
—
—

(a) Subsequent to March 31, 2016, we entered into 10,000 Bbls/day of two-way collars for July - December 2016 with a ceiling price of $50.00 and a floor price of $41.55. We also entered into 10,000 Bbls/day of 2016 three-way collars for May - December 2016 with a ceiling price of $58.51, a floor price of $48.00, and a sold put price of $40.00, traded in conjunction with sold call options of 10,000 Bbls/day for 2017 at $65.00.
(b) 
A counterparty has the option, exercisable on June 30, 2016, to extend three-way collars for 2,000 Bbls/day through the remainder of 2016 at a ceiling of $73.13, floor of $65.00 and sold put of $50.00.
(c) 
Call options settle monthly.
Natural Gas (a)
 
2016
Year Ending December 31,
 
Second Quarter
Third Quarter
Fourth Quarter
2017
Three-Way Collars (b)
 
 
 
 
Volume (MMBtu/day)
20,000
20,000
20,000
20,000
Price per MMBtu
 
 
 
 
Ceiling
$2.93
$2.93
$2.93
$3.07
Floor
$2.50
$2.50
$2.50
$2.75
Sold put
$2.00
$2.00
$2.00
$2.25
(a) 
Subsequent to March 31, 2016, we entered into 20,000 MMBtu/day of 2017 three-way collars with a ceiling price of $3.50, a floor price of $2.75, and a sold put price of $2.25.
(b) 
Counterparty has the option to execute fixed-price swaps (swaptions) at a weighted average price of $2.93 per MMBtu indexed to NYMEX Henry Hub, which is exercisable on December 22, 2016. If counterparty exercises, the term of the fixed-price swaps would be for the calendar year 2017 and, if all such options are exercised, 20,000 MMBtu per day.
v3.4.0.3
Incentive Based Compensation (Tables)
 3 Months Ended
Mar. 31, 2016
Incentive Based Compensation Plans [Abstract]  
Table of Incentive based compensation activity [Table Text Block]
The following table presents a summary of activity for the first three months of 2016: 
 
Stock Options
 
Restricted Stock Awards & Units
 
Number of
Shares
 
Weighted
Average
Exercise Price
 
Awards
 
Weighted
Average Grant
Date Fair Value
Outstanding at December 31, 2015
12,665,419

 

$29.97

 
4,017,344

 

$30.76

Granted
1,680,000

(a) 

$7.22

 
5,230,708

 

$7.91

Options Exercised/Stock Vested
—

 
—

 
(44,096
)
 

$32.01

Canceled
(181,681
)
 

$29.69

 
(220,614
)
 

$30.00

Outstanding at March 31, 2016
14,163,738

 

$27.27

 
8,983,342

 

$17.47

(a)    The weighted average grant date fair value of stock option awards granted was $1.97 per share.
v3.4.0.3
Reclassifications out of Accumulated Other Comprehensive Income Reclassifications out of Accumulated Other Comprehensive Income (Tables)
 3 Months Ended
Mar. 31, 2016
Reclassifications out of AccumulatedOtherComprehensiveIncome [Abstract]  
Schedule of Amounts Reclassified out of Accumulated Other Comprehensive Income [Table Text Block]
The following table presents a summary of amounts reclassified from accumulated other comprehensive loss:
 
Three Months Ended March 31,
 
 
(In millions)
2016
 
2015
 
Income Statement Line
 
 
 
 
Postretirement and postemployment plans
 
 
 
 
 
Amortization of actuarial loss
$
(3
)
 
$
(7
)
 
General and administrative
Net settlement loss
(48
)
 
(17
)
 
General and administrative
Net curtailment gain (loss)
—

 
5

 
General and administrative
 
(51
)
 
(19
)
 
Income (loss) from operations
 
19

 
7

 
Provision (benefit) for income taxes
Total reclassifications to expense
$
(32
)
 
$
(12
)
 
Net income (loss)
v3.4.0.3
Supplemental Cash Flow Information (Tables)
 3 Months Ended
Mar. 31, 2016
Supplemental Cash Flow Information [Abstract]  
Supplemental Cash Flow Information [Table Text Block]
Supplemental Cash Flow Information
 
Three Months Ended March 31,
(In millions)
2016
 
2015
Net cash (used in) operating activities:
 
 
 
Interest paid (net of amounts capitalized)
$
(87
)
 
$
(55
)
Income taxes paid to taxing authorities
(15
)
 
(47
)
Noncash investing activities:
 

 
 

Asset retirement cost increase
$
2

 
$
21

Asset retirement obligations assumed by buyer
54

 
—
v3.4.0.3
Variable Interest Entity (Details) - Variable Interest Entity, Not Primary Beneficiary [Member] - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Dec. 31, 2015
Variable Interest Entity [Line Items]    
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage 20.00%  
Recorded liability related to unconsolidated VIE $ 2 $ 2
Maximum exposure to loss related to unconsolidated VIE $ 472  
v3.4.0.3
Income per Common Share (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Earnings Per Share [Abstract]    
Net income (loss) $ (407) $ (276)
Weighted average common shares outstanding, basic 730 675
Weighted average common shares outstanding, diluted 730 675
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount 13 13
Basic:    
Net income (loss), per basic share $ (0.56) $ (0.41)
Diluted:    
Net income (loss), per diluted share $ (0.56) $ (0.41)
v3.4.0.3
Dispositions Dispositions (Details) - USD ($)
$ in Millions
 1 Months Ended 2 Months Ended 3 Months Ended
Apr. 30, 2016
Apr. 30, 2016
Mar. 31, 2016
Mar. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]        
Proceeds from Sale of Oil and Gas Property and Equipment     $ 17 $ 2
Subsequent Event [Member] | Wyoming Upstream and Midstream Assets [Member]        
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]        
Proceeds from Sale of Oil and Gas Property and Equipment $ 870      
Subsequent Event [Member] | Shenandoah in Gulf of Mexico, Piceance in Colorado, and West Texas [Member]        
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]        
Proceeds from Sale of Oil and Gas Property and Equipment   $ 80    
v3.4.0.3
Segment Information (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Segment Reporting Information [Line Items]    
Sales and other operating revenues $ 714 $ 1,280
Marketing revenues 58 204
Total revenues 772 1,484
Income from equity method investments 14 36
Net gain ( loss) on disposal of assets and other income (56) 12
Production expenses 328 444
Marketing costs 58 205
Exploration Expenses 24 90
Depreciation, depletion and amortization 609 821
Impairment of Oil and Gas Properties 1 0
Other expenses 260 [1] 278
Taxes other than income 48 67
Net interest and other 85 47
Income tax provision (benefit) (276) (144)
Segment income (loss) /Loss from continuing operations (407) (276)
Capital expenditures [2] 359 1,102
North America Exploration and Production [Member]    
Segment Reporting Information [Line Items]    
Sales and other operating revenues 493 850
Marketing revenues 31 178
Total revenues 524 1,028
Income from equity method investments 0 0
Net gain ( loss) on disposal of assets and other income 1 0
Production expenses 134 202
Marketing costs 32 180
Exploration Expenses 18 35
Depreciation, depletion and amortization 487 683
Impairment of Oil and Gas Properties 1  
Other expenses 118 [1] 117
Taxes other than income 42 61
Net interest and other 0 0
Income tax provision (benefit) (112) (89)
Segment income (loss) /Loss from continuing operations (195) (161)
Capital expenditures [2] 315 933
International Exploration and Production [Member]    
Segment Reporting Information [Line Items]    
Sales and other operating revenues 96 182
Marketing revenues 15 26
Total revenues 111 208
Income from equity method investments 14 36
Net gain ( loss) on disposal of assets and other income 6 10
Production expenses 53 67
Marketing costs 14 25
Exploration Expenses 6 55
Depreciation, depletion and amortization 50 64
Impairment of Oil and Gas Properties 0  
Other expenses 16 [1] 23
Taxes other than income 0 0
Net interest and other 0 0
Income tax provision (benefit) (12) (3)
Segment income (loss) /Loss from continuing operations 4 23
Capital expenditures [2] 32 146
Oil Sands Mining Segment [Member]    
Segment Reporting Information [Line Items]    
Sales and other operating revenues 148 225
Marketing revenues 12 0
Total revenues 160 225
Income from equity method investments 0 0
Net gain ( loss) on disposal of assets and other income 0 1
Production expenses 141 175
Marketing costs 12 0
Exploration Expenses 0 0
Depreciation, depletion and amortization 60 62
Impairment of Oil and Gas Properties 0  
Other expenses 7 [1] 9
Taxes other than income 5 5
Net interest and other 0 0
Income tax provision (benefit) (17) (6)
Segment income (loss) /Loss from continuing operations (48) (19)
Capital expenditures [2] 9 21
Corporate and Other [Member]    
Segment Reporting Information [Line Items]    
Sales and other operating revenues (23) [3] 23 [4]
Marketing revenues 0 0
Total revenues (23) 23
Income from equity method investments 0 0
Net gain ( loss) on disposal of assets and other income (63) [5] 1
Production expenses 0 0
Marketing costs 0 0
Exploration Expenses 0 0
Depreciation, depletion and amortization 12 12
Impairment of Oil and Gas Properties 0  
Other expenses [1] 119 [6] 129 [7]
Taxes other than income 1 1
Net interest and other 85 47
Income tax provision (benefit) (135) (46)
Segment income (loss) /Loss from continuing operations (168) (119)
Capital expenditures [2] 3 2
Workforce reduction 7 43
United States and Foreign Pension Plans Defined Benefit [Member]    
Segment Reporting Information [Line Items]    
Net settlement loss [8] 48 17
United States and Foreign Pension Plans Defined Benefit [Member] | Corporate and Other [Member]    
Segment Reporting Information [Line Items]    
Net settlement loss [8] $ 48 $ 17
[1] Includes other operating expenses and general and administrative expenses.
[2] Includes accruals.
[3] Unrealized loss on commodity derivative instruments.
[4] Unrealized gain on commodity derivative instruments.
[5] Related to the net loss on disposal of assets (see Note 5).
[6] Includes pension settlement loss of $48 million and severance related expenses associated with workforce reductions of $7 million (see Note 7).
[7] Includes $43 million of severance related expenses associated with a workforce reduction and pension settlement loss of $17 million (see Note 7).
[8] Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan's total service and interest cost for that year.
v3.4.0.3
Defined Benefit Postretirement Plans (Details) - USD ($)
$ in Millions
 3 Months Ended 9 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Dec. 31, 2016
Pension and Other Postretirement Benefit Contributions [Abstract]      
Pension Contributions $ 14    
Defined Benefit Plan, Benefits Paid 19    
Other Postretirement Benefits Payments 5    
Scenario, Forecast [Member]      
Pension and Other Postretirement Benefit Contributions [Abstract]      
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year     $ 48
United States and Foreign Pension Plans Defined Benefit [Member]      
Defined Benefit Plan Net Periodic Benefit Cost [Line Items]      
Service cost 6 $ 12  
Interest cost 11 14  
Expected return on plan assets (15) (19)  
Amortization:      
- prior service cost (credit) (2) 1  
-actuarial loss (gain) 3 7  
Net settlement loss [1] 48 17  
Defined Benefit Plan, Curtailments [2] 0 1  
Net periodic benefit cost 51 33  
Other Postretirement Benefit Plans Defined Benefit [Member]      
Defined Benefit Plan Net Periodic Benefit Cost [Line Items]      
Service cost 1 1  
Interest cost 3 3  
Expected return on plan assets 0 0  
Amortization:      
- prior service cost (credit) (1) (1)  
-actuarial loss (gain) 0 0  
Net settlement loss [1] 0 0  
Defined Benefit Plan, Curtailments [2] 0 (6)  
Net periodic benefit cost $ 3 $ (3)  
[1] Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan's total service and interest cost for that year.
[2] Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans
v3.4.0.3
Income Taxes (Details)
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Income Tax Disclosure [Abstract]    
Effective Income Tax Rate Reconciliation, Percent 40.00% 34.00%
Effective income tax rate excluding Libya 39.00% 31.00%
v3.4.0.3
Inventories (Details) - USD ($)
$ in Millions
Mar. 31, 2016
Dec. 31, 2015
Inventory Disclosure [Abstract]    
Liquid hydrocarbons natural gas and bitumen $ 33 $ 35
Supplies and other items 273 278
Total inventories, at cost $ 306 $ 313
v3.4.0.3
Property, Plant and Equipment (Details)
Boe in Millions, $ in Millions
Mar. 31, 2016
USD ($)
Dec. 31, 2015
USD ($)
Boe
Segment Reporting Information [Line Items]    
Property, plant and equipment, net $ 26,737 $ 27,061
LIBYAN ARAB JAMAHIRIYA    
Segment Reporting Information [Line Items]    
Property, plant and equipment, net 776  
Proved Developed and Undeveloped Reserves, Net (BOE) | Boe   235
North America Exploration and Production [Member]    
Segment Reporting Information [Line Items]    
Property, plant and equipment, net 14,953 $ 15,226
International Exploration and Production [Member]    
Segment Reporting Information [Line Items]    
Property, plant and equipment, net 2,521 2,533
Oil Sands Mining Segment [Member]    
Segment Reporting Information [Line Items]    
Property, plant and equipment, net 9,148 9,197
Corporate [Member]    
Segment Reporting Information [Line Items]    
Property, plant and equipment, net $ 115 $ 105
v3.4.0.3
Property, Plant and Equipment Property, Plant and Equipment (Details 2) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Dec. 31, 2015
Capitalized Exploratory Well Costs [Abstract]    
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year After Completion of Drilling $ 120 $ 85
Capitalized Exploratory Well Cost, Period Increase (Decrease) $ 35  
v3.4.0.3
Fair Value Measurements (Details-Recurring) - Fair Value, Measurements, Recurring [Member] - USD ($)
$ in Millions
Mar. 31, 2016
Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]    
Derivative Assets $ 63 $ 59
Derivative Liability 24 1
Commodity Contract [Member]    
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]    
Derivative Assets [1] 51 51
Derivative Liability [1] 24 1
Interest rate [Member]    
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]    
Derivative Assets 12 8
Fair Value, Inputs, Level 1 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]    
Derivative Assets 0 0
Derivative Liability 0 0
Fair Value, Inputs, Level 1 [Member] | Commodity Contract [Member]    
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]    
Derivative Assets [1] 0 0
Derivative Liability [1] 0 0
Fair Value, Inputs, Level 1 [Member] | Interest rate [Member]    
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]    
Derivative Assets 0 0
Fair Value Inputs Level 2 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]    
Derivative Assets 63 59
Derivative Liability 24 1
Fair Value Inputs Level 2 [Member] | Commodity Contract [Member]    
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]    
Derivative Assets [1] 51 51
Derivative Liability [1] 24 1
Fair Value Inputs Level 2 [Member] | Interest rate [Member]    
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]    
Derivative Assets 12 8
Fair Value, Inputs, Level 3 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]    
Derivative Assets 0 0
Derivative Liability 0 0
Fair Value, Inputs, Level 3 [Member] | Commodity Contract [Member]    
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]    
Derivative Assets [1] 0 0
Derivative Liability [1] 0 0
Fair Value, Inputs, Level 3 [Member] | Interest rate [Member]    
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]    
Derivative Assets $ 0 $ 0
[1] Derivative instruments are recorded on a net basis in the company's balance sheet (see Note 12).
v3.4.0.3
Fair Value Measurements (Details 2-Nonrecurring)
$ in Millions
 3 Months Ended
Mar. 31, 2016
USD ($)
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]  
Goodwill, Impairment Loss $ 0
v3.4.0.3
Fair Value Measurements (Details 3-Reported) - USD ($)
$ in Millions
Mar. 31, 2016
Dec. 31, 2015
Fair Value [Member]    
Financial Instruments, Financial Assets, Balance Sheet Groupings [Abstract]    
Other noncurrent financial assets $ 115 $ 104
Total financial assets 115 104
Financial liabilities    
Other current financial liabilities 34 34
Long-term debt, including current portion [1] 6,575 6,723
Deferred credits and other financial liabilities 104 97
Financial Liabilities Fair Value Disclosure 6,713 6,854
Carrying Amount [Member]    
Financial Instruments, Financial Assets, Balance Sheet Groupings [Abstract]    
Other noncurrent financial assets 120 118
Total financial assets 120 118
Financial liabilities    
Other current financial liabilities 33 33
Long-term debt, including current portion [1] 7,291 7,291
Deferred credits and other financial liabilities 105 95
Financial Liabilities Fair Value Disclosure $ 7,429 $ 7,419
[1] Excludes capital leases, debt issuance costs and interest rate swap adjustments.
v3.4.0.3
Derivatives (Details-BS) - USD ($)
$ in Millions
Mar. 31, 2016
Dec. 31, 2015
Derivatives Fair Value [Line Items]    
Derivative Asset, Fair Value, Gross Asset $ 63 $ 59
Derivative Asset, Fair Value, Gross Liability 7 1
Derivative Liability, Fair Value, Gross Liability 17  
Derivative Liability, Fair Value, Amount Not Offset Against Collateral 17  
Derivative Asset, Fair Value, Net 56 58
Derivative Liability, Fair Value, Gross Asset 0  
Designated as Hedging Instrument [Member]    
Derivatives Fair Value [Line Items]    
Derivative Asset, Fair Value, Gross Asset   8
Derivative Asset, Fair Value, Gross Liability   0
Derivative Asset, Fair Value, Net   8
Not Designated as Hedging Instrument [Member]    
Derivatives Fair Value [Line Items]    
Derivative Asset, Fair Value, Gross Asset 51 51
Derivative Asset, Fair Value, Gross Liability 7 1
Derivative Liability, Fair Value, Gross Liability 17  
Derivative Liability, Fair Value, Amount Not Offset Against Collateral 17  
Derivative Asset, Fair Value, Net 44 50
Derivative Liability, Fair Value, Gross Asset 0  
Commodity Contract [Member] | Other Noncurrent Assets [Member] | Not Designated as Hedging Instrument [Member]    
Derivatives Fair Value [Line Items]    
Derivative Liability, Fair Value, Gross Liability 17  
Derivative Liability, Fair Value, Amount Not Offset Against Collateral 17  
Derivative Liability, Fair Value, Gross Asset 0  
Commodity Contract [Member] | Other Current Assets [Member] | Not Designated as Hedging Instrument [Member]    
Derivatives Fair Value [Line Items]    
Derivative Asset, Fair Value, Gross Asset 51 51
Derivative Asset, Fair Value, Gross Liability 7 1
Derivative Asset, Fair Value, Net 44 50
Fair Value Hedging [Member] | Designated as Hedging Instrument [Member]    
Derivatives Fair Value [Line Items]    
Derivative Asset, Fair Value, Gross Asset 12  
Derivative Asset, Fair Value, Gross Liability 0  
Derivative Asset, Fair Value, Net 12  
Fair Value Hedging [Member] | Interest rate [Member] | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member]    
Derivatives Fair Value [Line Items]    
Derivative Asset, Fair Value, Gross Asset 12 8
Derivative Asset, Fair Value, Gross Liability 0 0
Derivative Asset, Fair Value, Net $ 12 $ 8
v3.4.0.3
Derivatives (Details 2-Fair Value Hedges) - Fair Value Hedging [Member] - Designated as Hedging Instrument [Member] - Interest Rate Contract [Member] - USD ($)
$ in Millions
Mar. 31, 2016
Dec. 31, 2015
Debentures Due 2017 [Member]    
Derivative [Line Items]    
Derivative, Notional Amount $ 600 $ 600
Weighted-average, LIBOR-based, floating rate 4.92% 4.73%
Debentures Due 2018 [Member]    
Derivative [Line Items]    
Derivative, Notional Amount $ 300 $ 300
Weighted-average, LIBOR-based, floating rate 4.77% 4.66%
v3.4.0.3
Derivatives (Details 3-Fair Value Hedges IS & OCI) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]    
Gain (Loss) on Fair Value Hedge Ineffectiveness, Net $ 0 $ 0
Net interest and other [Member]    
Derivative Instruments, Gain (Loss) [Line Items]    
Change in unrealized gain (loss) on hedged item in fair value hedge (4) (5)
Interest rate [Member] | Net interest and other [Member]    
Derivative Instruments, Gain (Loss) [Line Items]    
Gain (loss) on derivative instruments recognized in income $ 4 $ 5
v3.4.0.3
Derivatives Derivatives (Details 4-Non Hedges Commodity) (Details)
May. 05, 2016
BBL / Days
$ / bbl
Mar. 31, 2016
BBL / Days
MMBTU_per_day
$ / MMBTU
$ / bbl
Crude Oil Three-Way Collars for Second Quarter of Year 1    
Derivative [Line Items]    
Volume | BBL / Days [1],[2]   39,000
Ceiling Price [1],[2]   55.47
Floor Price [1],[2]   51.56
Sold Put Price [1],[2]   41.67
Crude Oil Three-Way Collars For Third Quarter of Year 1 [Member]    
Derivative [Line Items]    
Volume | BBL / Days [1],[2]   37,000
Ceiling Price [1],[2]   54.52
Floor Price [1],[2]   50.83
Sold Put Price [1],[2]   41.22
Crude Oil Three-Way Collars for Fourth Quarter of Year 1    
Derivative [Line Items]    
Volume | BBL / Days [1],[2]   37,000
Ceiling Price [1],[2]   54.52
Floor Price [1],[2]   50.83
Sold Put Price [1],[2]   41.22
Crude Oil Three-Way Collars For Year 2 [Member]    
Derivative [Line Items]    
Volume | BBL / Days [1],[2]   0
Ceiling Price [1],[2]   0
Floor Price [1],[2]   0
Sold Put Price [1],[2]   0
Crude Oil Options For the Second Quarter of Year 1 [Member]    
Derivative [Line Items]    
Volume | BBL / Days [2],[3]   10,000
Option Price [2],[3]   72.39
Crude Oil Options For the Third Quarter of Year 1 [Member]    
Derivative [Line Items]    
Volume | BBL / Days [2],[3]   10,000
Option Price [2],[3]   72.39
Crude Oil Options For the Fourth Quarter of Year 1 [Member]    
Derivative [Line Items]    
Volume | BBL / Days [2],[3]   10,000
Option Price [2],[3]   72.39
Crude Oil Options For Year 2 [Member]    
Derivative [Line Items]    
Volume | BBL / Days [2],[3]   25,000
Option Price [2],[3]   60.67
Crude Oil Swaps For the Second Quarter of Year 1 [Member]    
Derivative [Line Items]    
Volume | BBL / Days [2]   25,000
Option Price [2]   39.25
Crude Oil Swaps For the Third Quarter of Year 1 [Member]    
Derivative [Line Items]    
Volume | BBL / Days [2]   0
Option Price [2]   0
Crude Oil Swaps For the Fourth Quarter of Year 1 [Member]    
Derivative [Line Items]    
Volume | BBL / Days [2]   0
Option Price [2]   0
Crude Oil Swaps For Year 2 [Member]    
Derivative [Line Items]    
Volume | BBL / Days [2]   0
Option Price [2]   0
Crude Oil Three-Way Collars Option to Extend Jul-Dec 2016 [Member]    
Derivative [Line Items]    
Volume | BBL / Days   2,000
Ceiling Price   73.13
Floor Price   65.00
Sold Put Price   50.00
Natural Gas - Three-Way Collars For the Second Quarter of Year 1 [Member]    
Derivative [Line Items]    
Volume | MMBTU_per_day [4],[5]   20,000
Ceiling Price | $ / MMBTU [4],[5]   2.93
Floor Price | $ / MMBTU [4],[5]   2.50
Sold Put Price | $ / MMBTU [4],[5]   2.00
Natural Gas Three-Way Collars For the Third Quarter of Year 1 [Member]    
Derivative [Line Items]    
Volume | MMBTU_per_day [4],[5]   20,000
Ceiling Price | $ / MMBTU [4],[5]   2.93
Floor Price | $ / MMBTU [4],[5]   2.50
Sold Put Price | $ / MMBTU [4],[5]   2.00
Natural Gas Three-Way Collars For the Fourth Quarter of Year 1 [Member]    
Derivative [Line Items]    
Volume | MMBTU_per_day [4],[5]   20,000
Ceiling Price | $ / MMBTU [4],[5]   2.93
Floor Price | $ / MMBTU [4],[5]   2.50
Sold Put Price | $ / MMBTU [4],[5]   2.00
Natural Gas Three-Way Collars For Year 2 [Member]    
Derivative [Line Items]    
Volume | MMBTU_per_day [4],[5]   20,000
Ceiling Price | $ / MMBTU [4],[5]   3.07
Floor Price | $ / MMBTU [4],[5]   2.75
Sold Put Price | $ / MMBTU [4],[5]   2.25
Swaption [Member]    
Derivative [Line Items]    
Swap Price   2.93
Volume | MMBTU_per_day   20,000
Subsequent Event [Member] | Crude Oil Two-Way Collar Jul-Dec 2016 [Member]    
Derivative [Line Items]    
Volume | BBL / Days 10,000  
Ceiling Price 50.00  
Floor Price 41.55  
Subsequent Event [Member] | Crude Oil Three-Way Collars May-Dec 2016 [Member]    
Derivative [Line Items]    
Volume | BBL / Days 10,000  
Ceiling Price 58.51  
Floor Price 48.00  
Sold Put Price 40.00  
Subsequent Event [Member] | Crude Oil Sold Call 2017 [Member]    
Derivative [Line Items]    
Volume | BBL / Days 10,000  
Option Price 65.00  
Subsequent Event [Member] | Natural Gas Three-Way Collars 2017 [Member]    
Derivative [Line Items]    
Volume | BBL / Days 20,000  
Ceiling Price 3.50  
Floor Price 2.75  
Sold Put Price 2.25  
[1] A counterparty has the option, exercisable on June 30, 2016, to extend three-way collars for 2,000 Bbls/day through the remainder of 2016 at a ceiling of $73.13, floor of $65.00 and sold put of $50.00.
[2] Subsequent to March 31, 2016, we entered into 10,000 Bbls/day of two-way collars for July - December 2016 with a ceiling price of $50.00 and a floor price of $41.55. We also entered into 10,000 Bbls/day of 2016 three-way collars for May - December 2016 with a ceiling price of $58.51, a floor price of $48.00, and a sold put price of $40.00, traded in conjunction with sold call options of 10,000 Bbls/day for 2017 at $65.00.
[3] Call options settle monthly.
[4] Counterparty has the option to execute fixed-price swaps (swaptions) at a weighted average price of $2.93 per MMBtu indexed to NYMEX Henry Hub, which is exercisable on December 22, 2016. If counterparty exercises, the term of the fixed-price swaps would be for the calendar year 2017 and, if all such options are exercised, 20,000 MMBtu per day.
[5] Subsequent to March 31, 2016, we entered into 20,000 MMBtu/day of 2017 three-way collars with a ceiling price of $3.50, a floor price of $2.75, and a sold put price of $2.25.
v3.4.0.3
Derivatives Derivatives (Details 5-Non Hedges) (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Not Designated as Hedging Instrument [Member] | Commodity [Member] | Sales and other operating revenues [Member]    
Derivative Instruments, Gain (Loss) [Line Items]    
Derivative, Gain (Loss) on Derivative, Net $ 2 $ 26
v3.4.0.3
Incentive Based Compensation (Details)
 3 Months Ended
Mar. 31, 2016
$ / shares
shares
Stock Options  
Beginning year stock option awards | shares 12,665,419
Granted stock option awards | shares 1,680,000 [1]
Exercised stock option awards | shares 0
Canceled stock option awards | shares (181,681)
End of period stock option awards | shares 14,163,738
Beginning year weighted average exercise price $ 29.97
Granted weighted average exercise price 7.22
Exercises weighted average exercise price 0.00
Canceled weighted average exercise price 29.69
End of period weighted average exercise price 27.27
Stock options weighted average grant date fair value $ 1.97
[1] The weighted average grant date fair value of stock option awards granted was $1.97 per share.
v3.4.0.3
Incentive Based Compensation (Details 2-Restricted)
 3 Months Ended
Mar. 31, 2016
$ / shares
shares
Restricted Stock  
Beginning year unvested restricted stock | shares 4,017,344
Granted restricted stock | shares 5,230,708
Vested restricted stock | shares (44,096)
Forfeited restricted stock | shares (220,614)
End of period unvested restricted stock | shares 8,983,342
Beginning year weighted average grant date fair value unvested restricted stock | $ / shares $ 30.76
Granted restricted stock weighted average grant date fair value restricted stock | $ / shares 7.91
Vested restricted stock weighted average grant date fair value restricted stock | $ / shares 32.01
Forfeited restricted stock weighted average grant date fair value restricted stock | $ / shares 30.00
End of period weighted average grant date fair value unvested restricted stock | $ / shares $ 17.47
v3.4.0.3
Incentive Based Compensation (Details 3-Performance) - $ / shares
 3 Months Ended
Mar. 31, 2016
Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]    
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value $ 17.47 $ 30.76
Performance Unit [Member]    
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]    
Award Instruments Other Than Options Performance Unit Granted 1,205,517  
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value $ 3.72  
v3.4.0.3
Debt - Revolving Credit Facility (Details)
$ in Millions
Mar. 31, 2016
USD ($)
Feb. 29, 2016
USD ($)
Line of Credit Facility [Line Items]    
Line of Credit Facility, maximum borrowing capacity $ 3,300 $ 3,000
Line of Credit Facility, increase in borrowing capacity $ 300  
Ratio of indebtedness to net capital 0.27  
Maximum [Member]    
Line of Credit Facility [Line Items]    
Ratio of indebtedness to net capital 0.65  
v3.4.0.3
Reclassifications out of Accumulated Other Comprehensive Income Reclassifications out of Accumulated Other Comprehensive Income (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]    
Provision for income taxes $ 276 $ 144
Other insignificant, net of tax (109) (107)
Total reclassifications (407) (276)
Reclassification out of Accumulated Other Comprehensive Income [Member]    
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]    
Amortization of actuarial loss (3) (7)
Net settlement loss (48) (17)
Net curtailment gain (loss) 0 5
Income before income taxes (51) (19)
Provision for income taxes 19 7
Total reclassifications $ (32) $ (12)
v3.4.0.3
Stockholders' Equity (Details) - USD ($)
$ / shares in Units, $ in Millions
 1 Months Ended
Mar. 31, 2016
Dec. 31, 2015
Stockholders' Equity Attributable to Parent [Abstract]    
Shares Issued, Price Per Share $ 7.65  
Stock Issued During Period, Shares, New Issues 166,750,000  
Common Stock, Par or Stated Value Per Share $ 1 $ 1
Stock Issued $ 1,232  
v3.4.0.3
Supplemental Cash Flow Information (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Net cash provided by (used in) operating activities included:    
Interest paid (net of amounts capitalized) $ (87) $ (55)
Income taxes paid to taxing authorities (15) (47)
Noncash investing activities:    
Asset retirement costs capitalized 2 21
Asset retirement obligations assumed by buyer $ 54 $ 0
v3.4.0.3
Subsequent Events (Details) - USD ($)
$ in Millions
 1 Months Ended 3 Months Ended
Apr. 30, 2016
Mar. 31, 2016
Mar. 31, 2015
Subsequent Event [Line Items]      
Impairment of Oil and Gas Properties   $ 1 $ 0
Minimum [Member] | Gulf of Mexico Assets [Member] | Subsequent Event [Member]      
Subsequent Event [Line Items]      
Impairment of Oil and Gas Properties $ 140    
Maximum [Member] | Gulf of Mexico Assets [Member] | Subsequent Event [Member]      
Subsequent Event [Line Items]      
Impairment of Oil and Gas Properties $ 150     
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