MRO-2015.03.31-10Q


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, 2015

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 674,954,423 shares of Marathon Oil Corporation common stock outstanding as of April 30, 2015.




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).

 
Table of Contents
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 


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)
2015
 
2014
Revenues and other income:
 
 
 
Sales and other operating revenues, including related party
$
1,280

 
$
2,149

Marketing revenues
204

 
541

Income from equity method investments
36

 
137

Net gain on disposal of assets
1

 
2

Other income
11

 
20

Total revenues and other income
1,532

 
2,849

Costs and expenses:
 
 
 

Production
444

 
542

Marketing, including purchases from related parties
205

 
542

Other operating
107

 
103

Exploration
90

 
73

Depreciation, depletion and amortization
821

 
643

Impairments

 
17

Taxes other than income
67

 
95

General and administrative
171

 
187

Total costs and expenses
1,905

 
2,202

Income (loss) from operations
(373
)
 
647

Net interest and other
(47
)
 
(49
)
Income (loss) from continuing operations before income taxes
(420
)
 
598

Provision (benefit) for income taxes
(144
)
 
200

Income (loss) from continuing operations
(276
)
 
398

Discontinued operations

 
751

Net income (loss)
$
(276
)
 
$
1,149

Per basic share:
 

 
 

Income (loss) from continuing operations
$
(0.41
)
 
$
0.58

Discontinued operations
$

 
$
1.08

Net income (loss)
$
(0.41
)
 
$
1.66

Per diluted share:
 
 
 
Income (loss) from continuing operations
$
(0.41
)
 
$
0.57

Discontinued operations
$

 
$
1.08

Net income (loss)
$
(0.41
)
 
$
1.65

Dividends per share
$
0.21

 
$
0.19

Weighted average common shares outstanding:
 

 
 

Basic
675

 
693

Diluted
675

 
696

 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)
2015
 
2014
Net income (loss)
$
(276
)
 
$
1,149

Other comprehensive income (loss)
 

 
 

Postretirement and postemployment plans
 

 
 

Change in actuarial loss and other
76

 
(30
)
Income tax benefit (provision)
(27
)
 
10

Postretirement and postemployment plans, net of tax
49

 
(20
)
Comprehensive income (loss)
$
(227
)
 
$
1,129

 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)
2015
 
2014
Assets
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
1,126

 
$
2,398

Receivables, less reserve of $4 and $3
1,341

 
1,729

Inventories
379

 
357

Other current assets
122

 
109

Total current assets
2,968

 
4,593

Equity method investments
1,100

 
1,113

Property, plant and equipment, less accumulated depreciation,
 

 
 

depletion and amortization of $22,648 and $21,884
29,291

 
29,040

Goodwill
459

 
459

Other noncurrent assets
918

 
806

Total assets
$
34,736

 
$
36,011

Liabilities
 

 
 

Current liabilities:
 

 
 

Accounts payable
$
1,854

 
$
2,545

Payroll and benefits payable
127

 
191

Accrued taxes
260

 
285

Other current liabilities
252

 
290

Long-term debt due within one year
1,068

 
1,068

Total current liabilities
3,561

 
4,379

Long-term debt
5,326

 
5,323

Deferred tax liabilities
2,437

 
2,486

Defined benefit postretirement plan obligations
515

 
598

Asset retirement obligations
1,949

 
1,917

Deferred credits and other liabilities
288

 
288

Total liabilities
14,076

 
14,991

Commitments and contingencies


 


Stockholders’ Equity
 

 
 

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

 

Common stock:
 

 
 

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

 
770

Securities exchangeable into common stock – no shares issued or
 

 
 

outstanding (no par value, 29 million shares authorized)

 

Held in treasury, at cost – 95 million and 95 million shares
(3,634
)
 
(3,642
)
Additional paid-in capital
6,532

 
6,531

Retained earnings
17,220

 
17,638

Accumulated other comprehensive loss
(228
)
 
(277
)
Total stockholders' equity
20,660

 
21,020

Total liabilities and stockholders' equity
$
34,736

 
$
36,011

 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)
2015
 
2014
Increase (decrease) in cash and cash equivalents
 
 
 
Operating activities:
 

 
 

Net income (loss)
$
(276
)
 
$
1,149

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 

 
 

Discontinued operations

 
(751
)
Deferred income taxes
(179
)
 
89

Depreciation, depletion and amortization
821

 
643

Impairments

 
17

Pension and other postretirement benefits, net
(7
)
 
19

Exploratory dry well costs and unproved property impairments
67

 
43

Net gain on disposal of assets
(1
)
 
(2
)
Equity method investments, net
3

 
(42
)
Changes in:
 
 
 

Current receivables
388

 
(69
)
Inventories
(22
)
 
(41
)
Current accounts payable and accrued liabilities
(469
)
 
33

All other operating, net
(16
)
 
(19
)
Net cash provided by continuing operations
309

 
1,069

Net cash provided by discontinued operations

 
401

Net cash provided by operating activities
309

 
1,470

Investing activities:
 

 
 

Additions to property, plant and equipment
(1,452
)
 
(1,004
)
Disposal of assets
2

 
2,123

Investments - return of capital
10

 
20

Investing activities of discontinued operations

 
(96
)
All other investing, net
(2
)
 
5

Net cash provided by (used in) investing activities
(1,442
)
 
1,048

Financing activities:
 

 
 

Commercial paper, net

 
(135
)
Purchases of common stock

 
(551
)
Dividends paid
(142
)
 
(133
)
All other financing, net
4

 
9

Net cash used in financing activities
(138
)
 
(810
)
Effect of exchange rate on cash and cash equivalents:
 
 
 
Continuing operations
(1
)
 

Discontinued operations

 
(8
)
Net increase (decrease) in cash and cash equivalents
(1,272
)
 
1,700

Cash and cash equivalents at beginning of period
2,398

 
264

Cash and cash equivalents at end of period
$
1,126

 
$
1,964

 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 Securities and Exchange Commission ("SEC") and do not include all of the information and disclosures required by accounting principles generally accepted in the United States ("U.S. GAAP") for complete financial statements.
As a result of the sale of our Angola assets and our Norway business in 2014, both are reflected as discontinued operations. The disclosures in this report related to results of operations and cash flows are presented on the basis of continuing operations, unless otherwise noted.
These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Marathon Oil Corporation 2014 Annual Report on Form 10-K.  The results of operations for the first quarter of 2015 are not necessarily indicative of the results to be expected for the full year.
2.   Accounting Standards
Not Yet Adopted
In April 2015, the FASB issued an update that requires debt issuance costs to be presented in the balance sheet as a direct reduction from the associated debt liability. This standard is effective for us in the first quarter of 2016 and will be applied on a retrospective basis. Early adoption is permitted, including in interim periods. 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 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 if 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 and early adoption is permitted, including in interim periods. 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 United States ("U.S.") auditing standards.  This standard is effective for us in the first quarter of 2017 and 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 also eliminates industry-specific revenue guidance, 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 2017 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 not 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 April 2014, the FASB issued an amendment to accounting standards that changes the criteria for reporting discontinued operations while enhancing related disclosures. Under the amendment, only disposals representing a strategic shift in operations should be presented as discontinued operations. Expanded disclosures about the assets, liabilities, income and expenses of discontinued operations are required.  In addition, disclosure of the pretax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting will be made in order to provide users with information about the ongoing trends in an organization’s results from continuing operations.  The amendments were effective for us in the first quarter of 2015 and apply to dispositions or classifications as held for sale thereafter. Adoption of this standard did not impact our consolidated results of operations, financial position or cash flows.

6


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


3.   Variable Interest Entity
The owners of the Athabasca Oil Sands Project ("AOSP"), 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 $1 million recorded at March 31, 2015 and $3 million at December 31, 2014.  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 $506 million as of March 31, 2015.  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 (loss) per share assumes exercise of stock options, provided the effect is not antidilutive. The per share calculations below exclude 13 million and 5 million stock options for the first three months of 2015 and 2014 that were antidilutive.
 
Three Months Ended March 31,
(In millions, except per share data)
2015
 
2014
Income (loss) from continuing operations
$
(276
)
 
$
398

Discontinued operations

 
751

Net income (loss)
$
(276
)
 
$
1,149

 
 
 
 
Weighted average common shares outstanding
675

 
693

Effect of dilutive securities

 
3

Weighted average common shares, diluted
675

 
696

Per basic share:
 
 
 
Income (loss) from continuing operations
$
(0.41
)
 
$
0.58

Discontinued operations
$

 
$
1.08

Net income (loss)
$
(0.41
)
 
$
1.66

Per diluted share:
 
 
 
Income (loss) from continuing operations
$
(0.41
)
 
$
0.57

Discontinued operations
$

 
$
1.08

Net income (loss)
$
(0.41
)
 
$
1.65


7


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


5.
Dispositions
2014 - International E&P Segment
In the second quarter of 2014, we entered into an agreement to sell our Norway business, including the operated Alvheim floating production, storage and offloading vessel, 10 operated licenses and a number of non-operated licenses on the Norwegian Continental Shelf in the North Sea.  The transaction closed during the fourth quarter of 2014.
Our Norway business was reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for 2014. Select amounts reported in discontinued operations follow:
 
Three Months Ended March 31,
(In millions)
2014
Revenues applicable to discontinued operations
$
680

Pretax income from discontinued operations
$
532

After-tax income from discontinued operations
$
142

 
 
In the first quarter of 2014, we closed the sales of our non-operated 10% working interests in the Production Sharing Contracts and Joint Operating Agreements for Angola Blocks 31 and 32 for aggregate proceeds of approximately $2 billion and recorded a $576 million after-tax gain on sale. Included in the after-tax gain is a deferred tax benefit reflecting our ability to utilize foreign tax credits that otherwise would have needed a valuation allowance.
Our Angola operations are reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for the prior period. Select amounts reported in discontinued operations follow:
 
Three Months Ended March 31,
(In millions)
2014
Revenues applicable to discontinued operations
$
58

Pretax income from discontinued operations, before gain
$
51

Pretax gain on disposition of discontinued operations
$
470

After-tax income from discontinued operations
$
609

 
 
6.    Segment Information
  We are a global energy company with operations in North America, Europe and Africa. Each of our three reportable operating segments is organized and managed based upon both geographic location and the nature of the products and services it offers.
North America E&P ("N.A. E&P") – explores for, produces and markets crude oil and condensate, natural gas liquids ("NGLs") and natural gas in North America;
International E&P ("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 Equatorial Guinea ("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 from continuing 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. These 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, unrealized gains or losses on crude oil derivative instruments, or other items that affect comparability (as determined by the CODM) also are not allocated to operating segments.
As discussed in Note 5, as a result of the sale of our Angola assets and our Norway business in 2014, both are reflected as discontinued operations and excluded from the International E&P segment for 2014.

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) /Income (loss) from continuing operations
$
(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 crude oil derivative instruments.
(d) 
Includes $43 million of severance related expenses associated with a workforce reduction and a pension settlement loss of $17 million.
 
Three Months Ended March 31, 2014
 
 
 
Not Allocated
 
 
(In millions)
N.A. E&P
 
Int'l E&P
 
OSM
 
to Segments
 
Total
Sales and other operating revenues
$
1,392

 
$
380

 
$
377

 
$

 
$
2,149

Marketing revenues
440

 
70

 
31

 

 
541

Total revenues
1,832

 
450

 
408

 

 
2,690

Income from equity method investments

 
137

 

 

 
137

Net gain on disposal of assets and other income
3

 
17

 
2

 

 
22

Less:
 
 
 
 
 
 
 
 
 
Production expenses
211

 
100

 
231

 

 
542

Marketing costs
440

 
71

 
31

 

 
542

Exploration expenses
57

 
16

 

 

 
73

Depreciation, depletion and amortization
515

 
71

 
45

 
12

 
643

Impairments
17

 

 

 

 
17

Other expenses (a)
110

 
38

 
13

 
129

(c) 
290

Taxes other than income
90

 

 
5

 

 
95

Net interest and other

 

 

 
49

 
49

Income tax provision (benefit)
153

 
87

 
21

 
(61
)
 
200

Segment income/Income from continuing operations
$
242

 
$
221

 
$
64

 
$
(129
)
 
$
398

Capital expenditures (b)
$
867

 
$
105

 
$
68

 
$
3

 
$
1,043

(a)Includes other operating expenses and general and administrative expenses.
(b)Includes accruals.
(c)    Includes pension settlement loss of $63 million
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

9


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


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)
2015
 
2014
 
2015
 
2014
Service cost
$
12

 
$
12

 
$
1

 
$
1

Interest cost
14

 
16

 
3

 
3

Expected return on plan assets
(19
)
 
(18
)
 

 

Amortization:
 

 
 

 
 

 
 

– prior service cost (credit)
1

 
1

 
(1
)
 
(1
)
– actuarial loss
7

 
6

 

 

Net settlement loss (a)
17

 
63

 

 

Net curtailment loss (gain) (b)
1

 

 
(6
)
 

Net periodic benefit cost (credit)
$
33

 
$
80

 
$
(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 the workforce reduction, which reduced the future expected years of service for employees participating in the plans.
 
 
 
 
 
 
 
 
During the first quarter of 2015, we recorded the effects of a workforce reduction and a pension plan amendment. The pension plan amendment freezes the final average pay used to calculate the formula benefit and is effective July 6, 2015. Additionally, during the first quarter of 2015 and 2014, we recorded the effects of partial 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 (credit).
During the first three months of 2015, we made contributions of $23 million to our funded pension plans.  We expect to make additional contributions up to an estimated $70 million to our funded pension plans over the remainder of 2015.  During the first three months of 2015, we made payments of $12 million and $3 million related to unfunded pension plans and other postretirement benefit plans, respectively.
8.   Income Taxes
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 (benefits) 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 on continuing operations for the first three months of 2015 and 2014 were 34% and 33%.  The tax provision (benefit) applicable to Libyan ordinary income (loss) was recorded as a discrete item in the first three months of 2015 and 2014.  Excluding Libya, the effective tax rates on continuing operations would be 31% and 36% for the first three months of 2015 and 2014. In Libya, there remains uncertainty around the timing of future production and sales levels. Reliable estimates of 2015 and 2014 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, for the first three months of 2015 and 2014, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss).
9.   Inventories
 Inventories of liquid hydrocarbons, natural gas and bitumen are carried at the lower of cost or market value. Materials and supplies are valued at weighted average cost and reviewed for obsolescence or impairment when market conditions indicate.
 
March 31,
 
December 31,
(In millions)
2015
 
2014
Liquid hydrocarbons, natural gas and bitumen
$
54

 
$
58

Supplies and other items
325

 
299

Inventories, at cost
$
379

 
$
357


10


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


10.  Property, Plant and Equipment, net of Accumulated Depreciation, Depletion and Amortization
 
March 31,
 
December 31,
(In millions)
2015
 
2014
North America E&P
$
16,954

 
$
16,717

International E&P
2,803

 
2,741

Oil Sands Mining
9,415

 
9,455

Corporate
119

 
127

Net property, plant and equipment
$
29,291


$
29,040

Our Libya operations continue to be impacted by civil unrest and, in December 2014, Libya’s National Oil Corporation once again declared force majeure at the Es Sider oil terminal, as disruptions from civil unrest continue. Considerable uncertainty remains around the timing of future production and sales levels.
As of March 31, 2015, our net property, plant and equipment investment in Libya is $769 million, and total proved reserves (unaudited) in Libya as of December 31, 2014 are 243 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 continues to exceed the carrying value of $769 million by a material amount.
Exploratory well costs capitalized greater than one year after completion of drilling were $126 million as of March 31, 2015 and December 31, 2014.
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, 2015 and December 31, 2014 by fair value hierarchy level.
 
March 31, 2015
(In millions)
Level 1
 
Level 2
 
Level 3
 
Total
Derivative instruments, assets
 
 
 
 
 
 
 
     Commodity
$

 
$
23

 
$

 
$
23

     Interest rate

 
13

 

 
13

Derivative instruments, assets
$

 
$
36

 
$

 
$
36

 
December 31, 2014
(In millions)
Level 1
 
Level 2
 
Level 3
 
Total
Derivative instruments, assets
 
 
 
 
 
 
 
Interest rate
$

 
$
8

 
$

 
$
8

Derivative instruments, assets
$

 
$
8

 
$

 
$
8

Commodity derivatives include three-way collars and swaptions. Three-way collars and swaptions are measured at fair value using the Black-Scholes Model and the Black Model, respectively. 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.

11


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Fair Values - Nonrecurring
The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.
 
Three Months Ended March 31,
 
2015
 
2014
(In millions)
Fair Value
 
Impairment
 
Fair Value
 
Impairment
Long-lived assets held for use
$

 
$

 
$

 
$
17

 
 
 
 
 
 
 
 
No impairments were recorded in the first three months of 2015. In the second half of 2014, commodity prices began a substantial decline which persisted into the first quarter of 2015. As this period of sustained reduced commodity prices continues, it could result in non-cash impairment charges related to long-lived assets in future periods.
The Ozona development in the Gulf of Mexico (held by our North America E&P segment) ceased producing in 2013, at which time those long-lived assets were fully impaired. In the first quarter of 2014, we recorded an additional impairment of $17 million related to Ozona as a result of estimated abandonment cost revisions. The fair value was measured using an income approach based upon forecasted future abandonment costs, which are Level 3 inputs. 
Fair Values – Financial Instruments
Our current assets and liabilities include financial instruments, the most significant of which are receivables, long-term debt due within one year, 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 investment-grade 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, 2015 and December 31, 2014.
 
March 31, 2015
 
December 31, 2014
 
Fair
 
Carrying
 
Fair
 
Carrying
(In millions)
Value
 
Amount
 
Value
 
Amount
Financial assets
 
 
 
 
 
 
 
Other noncurrent assets
$
135

 
$
134

 
$
132

 
$
129

Total financial assets  
135

 
134

 
132

 
129

Financial liabilities
 

 
 

 
 

 
 

     Other current liabilities
13

 
13

 
13

 
13

     Long-term debt, including current portion (a)
6,980

 
6,361

 
6,887

 
6,360

Deferred credits and other liabilities
68

 
68

 
69

 
68

Total financial liabilities  
$
7,061

 
$
6,442

 
$
6,969

 
$
6,441

(a)    Excludes capital leases.
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


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


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. Netting is assessed by counterparty, and as of March 31, 2015 and December 31, 2014, there were no offsetting amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts along with where they appear on the consolidated balance sheets as of March 31, 2015 and December 31, 2014.
 
March 31, 2015
 
 
(In millions)
Asset
 
Liability
 
Net Asset
 
Balance Sheet Location
Fair Value Hedges
 
 
 
 
 
 
 
     Interest rate
$
13

 
$

 
$
13

 
Other noncurrent assets
Total Designated Hedges
13

 

 
13

 
 
 
 
 
 
 
 
 
 
Not Designated as Hedges
 
 
 
 
 
 
 
     Commodity
23

 

 
23

 
Other current assets
Total Not Designated as Hedges
23

 

 
23

 
 
     Total
$
36

 
$

 
$
36

 
 
 
 
 
 
 
 
 
 
 
December 31, 2014
 
 
(In millions)
Asset
 
Liability
 
Net Asset
 
Balance Sheet Location
Fair Value Hedges
 
 
 
 
 
 
 
     Interest rate
$
8

 
$

 
$
8

 
Other noncurrent assets
Total Designated Hedges
$
8

 
$

 
$
8

 
 
Derivatives Designated as Fair Value Hedges
The following table presents, by maturity date, information about our interest rate swap agreements as of March 31, 2015 and December 31, 2014, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.
 
March 31, 2015
 
December 31, 2014
 
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

4.66
%
 
$
600

4.64
%
March 15, 2018
$
300

4.51
%
 
$
300

4.49
%

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. The foreign currency forwards were used to hedge the current Norwegian tax liability of our Norway business that was sold in the fourth quarter of 2014. Those instruments outstanding were transferred to the purchaser of the Norway business upon closing of the sale. There is no ineffectiveness related to the fair value hedges.
 
 
Gain (Loss)
 
 
 
Three Months Ended March 31,
(In millions)
Income Statement Location
 
2015
 
2014
Derivative
 
 
 
 
 
Interest rate
Net interest and other
 
$
5

 
$
(1
)
Foreign currency
Discontinued operations
 
$

 
$
3

Hedged Item
 
 
 

 
 

Long-term debt
Net interest and other
 
$
(5
)
 
$
1

Accrued taxes
Discontinued operations
 
$

 
$
(3
)
 Derivatives not Designated as Hedges
During the first quarter of 2015, we entered into crude oil derivatives related to a portion of our forecasted North America E&P sales through December 2015. These commodity derivatives are three-way collars which 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 crude oil 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 New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI") price plus the difference between the floor and the sold put price. These commodity derivatives were not designated as hedges and are shown in the table below:
Three-Way Collars
 
 
  Barrels per day
25,000
  Index
NYMEX WTI
  Weighted average price per barrel:
 
    Ceiling
$71.67
    Floor
$55.00
    Sold put
$40.00
  Remaining Term (a)
April - December 2015
(a) 
Counterparties have the option to execute fixed-price swaps (swaptions) at a weighted average price
of $71.67 per barrel indexed to NYMEX WTI, which is exercisable on October 30, 2015. If
counterparties exercise, the term of the fixed-price swaps would be for calendar year 2016 and, if all
such options are exercised, 25,000 barrels per day.
The impact of these commodity derivative instruments appears in sales and other operating revenues and was a net gain of $26 million in the first quarter of 2015. There were no commodity derivative instruments in the first quarter of 2014.

14


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


13.    Incentive Based Compensation
 Stock option and restricted stock awards
  The following table presents a summary of stock option and restricted stock award activity for the first three months of 2015
 
Stock Options
 
Restricted Stock
 
Number of
Shares
 
Weighted
Average
Exercise Price
 
Awards
 
Weighted
Average Grant
Date Fair Value
Outstanding at December 31, 2014
13,427,836

 

$29.68

 
3,448,353

 

$34.04

Granted
724,082

(a) 

$29.06

 
317,563

 

$28.93

Options Exercised/Stock Vested
(99,441
)
 

$17.36

 
(257,390
)
 

$34.94

Canceled
(272,031
)
 

$34.07

 
(414,431
)
 

$33.78

Outstanding at March 31, 2015
13,780,446

 

$29.65

 
3,094,095

 

$33.48

(a)    The weighted average grant date fair value of stock option awards granted was $6.84 per share.
Stock-based performance unit awards
 During the first three months of 2015, we granted 382,335 stock-based performance units to certain officers. The grant date fair value per unit was $31.77.
14.  Reclassifications Out of Accumulated Other Comprehensive Income (Loss)
The following table presents a summary of amounts reclassified from accumulated other comprehensive income (loss) to income (loss) from continuing operations in their entirety:
 
Three Months Ended March 31,
 
 
(In millions)
2015
 
2014
 
Income Statement Line
 
 
 
 
Postretirement and postemployment plans
 
 
 
 
 
Amortization of actuarial loss
$
(7
)
 
$
(6
)
 
General and administrative
Net settlement loss
(17
)
 
(63
)
 
General and administrative
Net curtailment gain
5

 

 
General and administrative
 
(19
)
 
(69
)
 
Income (loss) from operations
 
7

 
23

 
Benefit for income taxes
Total reclassifications
$
(12
)
 
$
(46
)
 
Income (loss) from continuing operations
15.  Supplemental Cash Flow Information
 
Three Months Ended March 31,
(In millions)
2015
 
2014
Net cash provided by (used in) operating activities:
 
 
 
Interest paid (net of amounts capitalized)
$
(55
)
 
$
(56
)
Income taxes paid to taxing authorities (a)
(47
)
 
(453
)
Net cash provided by (used in) financing activities:
 
 
 
Commercial paper, net:
 

 
 

Issuances
$

 
$
2,235

Repayments

 
(2,370
)
Commercial paper, net

 
(135
)
Noncash investing activities, related to continuing operations:
 

 
 

Asset retirement costs capitalized
$
21

 
$
37

Asset retirement obligations assumed by buyer

 
43

Receivable for disposal of assets

 
44

(a) 
Income taxes paid to taxing authorities included $357 million related to discontinued operations in the first three months of 2014 .

15


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


16.   Commitments and Contingencies
 We are a defendant in a number of lawsuits arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims 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.  




16




Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
  We are a global energy company with operations in North America, Europe and Africa. Each of our three reportable operating segments is organized and managed based upon both geographic location and the nature of the products and services it offers.
North America E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in North America;
International 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 – 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.
As a result of the sale of our Angola assets and our Norway business in 2014, both are reflected as discontinued operations. The disclosures in this report related to results of operations and cash flows are presented on the basis of continuing operations, unless otherwise noted.
Executive Overview
Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows and their subsequent reinvestment into our business. The substantial decline in commodity prices that began in the second half of 2014 persisted through the first quarter of 2015. We believe we can manage in this lower commodity price cycle through a continued focus on development in our three U.S. resource plays, operational execution and efficiencies, and capital discipline, all while maintaining financial flexibility.
Our significant first quarter 2015 financial results and operating activities include the following:
Loss from continuing operations per diluted share of $(0.41) as compared to income from continuing operations of $0.57 per diluted share in the first quarter of 2014
Increased company-wide net sales volumes from continuing operations by 19% from 386 thousand barrels of oil equivalent per day ("mboed") in the first quarter of 2014 to 459 mboed
Net sales volumes from our three U.S. resource plays increased 49% from 154 mboed in the first quarter of 2014 to 229 mboed
Achieved 98% average operational availability for our operated assets
Reduced North America E&P production expenses per boe by 28% compared to the first quarter of 2014
Completed our previously announced workforce reduction, incurring severance and related expenses of $43 million
Operating cash flow provided by continuing operations of $309 million, compared to $1.1 billion for first quarter of 2014
$3.6 billion of liquidity at the end of the first quarter, comprised of $1.1 billion in cash and $2.5 billion in the unused revolving credit facility; credit facility capacity increased to $3 billion after quarter end
Cash-adjusted debt-to-capital ratio of 20% at March 31, 2015, as compared with 16% at December 31, 2014
We continue to optimize our resource allocation and portfolio given the current price environment. We now expect our full-year 2015 capital, investment and exploration budget to be $3.3 billion, a decrease of $0.2 billion from our previously announced plan. We continue to estimate our full-year North America E&P and International E&P production volumes (excluding Libya) to be 370 - 390 net mboed. We are targeting to generate at least $500 million from select non-core asset sales as we continue our ongoing portfolio management. See Cash Flows and Liquidity for further detail underlying our capital allocation.

    




17


Operations
North America E&P--Production
North America E&P segment average net sales volumes in the first quarter of 2015 increased 33% compared to the first quarter of 2014.  Net liquid hydrocarbon sales volumes increased 60 thousand barrels per day ("mbbld") and net natural gas sales volumes increased 59 million cubic feet per day ("mmcfd") in the first quarter of 2015 compared to the first quarter of 2014, reflecting continued growth from the combined U.S. resource plays.
 
Three Months Ended March 31,
 
2015
 
2014
Net Sales Volumes
 
 
 
Crude Oil and Condensate (mbbld)
 
 
 
Bakken
51
 
38
Eagle Ford
92
 
62
Oklahoma Resource Basins
5
 
2
Other North America (a)
36
 
36
Total Crude Oil and Condensate
184
 
138
Natural Gas Liquids (mbbld)
 
 
 
Bakken
3
 
2
Eagle Ford
27
 
16
Oklahoma Resource Basins
7
 
4
Other North America(a)
2
 
3
Total Natural Gas Liquids
39
 
25
Total Liquid Hydrocarbons (mbbld)
 
 
 
Bakken
54
 
40
Eagle Ford
119
 
78
Oklahoma Resource Basins
12
 
6
Other North America(a)
38
 
39
Total Liquid Hydrocarbons
223
 
163
Natural Gas (mmcfd)
 
 
 
Bakken
20
 
16
Eagle Ford
169
 
107
Oklahoma Resource Basins
78
 
54
Other North America(a)
92
 
123
Total Natural Gas
359
 
300
Equivalent Barrels (mboed)
 
 
 
Bakken
57
 
43
Eagle Ford
147
 
96
Oklahoma Resource Basins
25
 
15
Other North America(a)
54
 
59
Total North America E&P
283
 
213
(a)     Includes Gulf of Mexico and other conventional onshore U.S. production.


18


The following table presents a summary of our operated drilling activity in the U.S. resource plays:
 
Three Months Ended March 31,
 
2015
 
2014
Gross Operated
 
 
 
Eagle Ford:
 
 
 
Wells drilled to total depth
88

 
83

Wells brought to sales
91

 
49

Bakken:
 
 
 
Wells drilled to total depth
20

 
16

Wells brought to sales
24

 
15

Oklahoma Resource Basins:
 
 
 
Wells drilled to total depth
8

 
5

Wells brought to sales
5

 
4

Eagle Ford – Average net sales volumes from Eagle Ford were 147 mboed in the first quarter of 2015 compared to 96 mboed in the same period for 2014, for an increase of 53%. Approximately 63% of first quarter sales was crude oil and condensate, 18% was NGLs and 19% was natural gas. Our average time to drill an Eagle Ford well in first quarter 2015, spud-to-total depth, was 12 days. Our high-density pad drilling continues to average four wells per pad.
Included with the Eagle Ford well counts noted in the table above, we brought online nine gross operated Austin Chalk wells, compared to one in the same quarter of 2014. Twenty-four additional Austin Chalk wells are currently being drilled, completed or awaiting first production. We brought online our first four-well "stack-and-frac" pilot which included Austin Chalk, Upper Eagle Ford and two Lower Eagle Ford wells. Early performance from this pilot is encouraging.
Bakken – Average net sales volumes from the Bakken shale were 57 mboed in the first quarter of 2015 compared to 43 mboed in the same period for 2014, for an increase of 33%. Our Bakken production averaged approximately 89% crude oil, 5% NGLs and 6% natural gas. Our time to drill a Bakken well, spud-to-total depth, averaged 17 days in the first quarter of 2015.
The Bakken enhanced completion design pilot program has concluded with promising early results, which resulted in a revised standard well completion design for future wells. Data from the first 23 wells suggest greater than 30% improvement in cumulative production after 90 days when compared to direct offset performance. All 24 of the wells brought to sales in the first quarter incorporated an enhanced completion design, optimizing proppant loading, frac fluid volumes and stage density. Early performance of the first high-density pilot (six wells per horizon) is encouraging, and the second high-density spacing pilot recently started flowback. Additionally, we recently completed drilling our third high-density spacing pilot.
Oklahoma Resource Basins – Net sales volumes from the Oklahoma Resource Basins averaged 25 mboed in the first quarter of 2015 compared to 15 mboed in the comparable 2014 period, for an increase of 67%. Approximately 48% of first quarter 2015 net production was liquids and 52% was natural gas. All five gross operated wells brought to sales this quarter were in the SCOOP with three of the wells in the southern SCOOP. We plan to maintain our program of two operated rigs in the Oklahoma Resource Basins.
Additionally, we continue to leverage the benefit of participation in outside-operated wells and plan to participate in approximately 50 outside-operated wells in 2015 in the SCOOP Woodford, SCOOP Springer and STACK areas. In the first quarter of 2015, we participated in five high-density outside-operated spacing pilots in the SCOOP area; three in the Woodford (80-128 acre spacing) and two in the emerging Springer shale (105-128 acre spacing) overlaying the Woodford. The Woodford pilots include one high-density 10-well pilot comprised of five wells in the upper Woodford and five wells in the middle Woodford.
North America E&P--Exploration
Gulf of Mexico - We expect to spud the Solomon exploration prospect on Walker Ridge Block 225 in the second quarter of 2015. We currently hold a 78% operated working interest in the prospect, but are in advanced discussions to farm down our interest, and anticipate those discussions to be finalized in the second quarter of 2015.





19


International E&P--Production
International E&P segment average net sales volumes in the first quarter of 2015 decreased 8% compared to the first quarter of 2014, reflecting field decline and a planned turnaround at the AMPCO methanol facility completed in first quarter 2015.
 
Three Months Ended March 31,
 
2015
 
2014
Net Sales Volumes
 
 
 
Crude Oil and Condensate (mbbld)
 
 
 
Equatorial Guinea
18

 
24

United Kingdom
13

 
12

Total Crude Oil and Condensate
31

 
36

Natural Gas Liquids (mbbld)
 
 
 
Equatorial Guinea
10

 
11

United Kingdom

 
1

Total Natural Gas Liquids
10

 
12

Total Liquid Hydrocarbons (mbbld)
 
 
 
Equatorial Guinea
28

 
35

United Kingdom
13

 
13

Total Liquid Hydrocarbons
41

 
48

Natural Gas (mmcfd)
 
 
 
Equatorial Guinea
418

 
435

United Kingdom(a)
33

 
30

Libya

 
3

Total Natural Gas
451

 
468

Equivalent Barrels (mboed)
 
 
 
Equatorial Guinea
97

 
108

United Kingdom(a)
19

 
18

Total International E&P (mboed)
116

 
126

Net Sales Volumes of Equity Method Investees
 
 
 
LNG (mtd)
6,275

 
6,579

Methanol (mtd)
884

 
1,153

(a) 
Includes natural gas acquired for injection and subsequent resale of 10 mmcfd and 7 mmcfd for the first quarters of 2015 and 2014.
Equatorial Guinea – Average net sales volumes were 97 mboed in the first quarter of 2015 compared to 108 mboed in the same period of 2014 due to field decline and a planned turnaround completed in the first quarter of 2015 at the AMPCO methanol facility. In April, drilling commenced on the Alba C21 development well.
United Kingdom – Average net sales volumes were 19 mboed in the first quarter of 2015, relatively flat as compared to 18 mboed in the same period of 2014. Field decline was offset by the addition of South Brae infill wells brought online in late 2014 and first quarter of 2015, as well as the first of two subsea development wells at West Brae brought online in the first quarter 2015. Drilling was completed on a second West Brae well, which is expected to be online in the second quarter.
Libya – We had no sales in the first quarter of 2015 as a result of continued civil unrest. In December 2014, Libya’s National Oil Corporation reinstated force majeure at the Es Sider oil terminal, as disruptions from civil unrest continue. Considerable uncertainty remains around the timing of future production and sales levels.
International E&P--Exploration
Equatorial Guinea - Drilling and evaluation of the offshore Rodo-1 exploration well was completed in the first quarter of 2015. The well has been temporarily abandoned while further studies progress to evaluate commerciality of the light oil discovery.
Kurdistan Region of Iraq – On the operated Harir Block, the Mirawa-2 appraisal well was spud in December. Testing is in progress and is expected to be completed in the second quarter. We hold a 45% working interest in the block.

20


Oil Sands Mining
 Our net synthetic crude oil sales volumes were 60 mbbld in the first quarter of 2015 compared to 47 mbbld in the same period of 2014. Higher net sales volumes, up 28% in the first quarter of 2015 compared to the year-ago quarter were primarily due to improved reliability. The Quest Carbon Capture and Storage project reached mechanical completion in February and is on schedule for fourth quarter 2015 start-up. A 55-day planned turnaround at the base upgrader began in April, coupled with a planned turnaround at the Muskeg River Mine, followed by an extended pitstop at the Jackpine Mine. We hold a 20% non-operated working interest in the AOSP.  

21



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 significantly lower in the first three months of 2015 as compared to 2014; as a result, we experienced significant 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 2015 and 2014.
 
Three Months Ended March 31,
 
2015
 
2014
Average Price Realizations (a)
 
 
 
Crude Oil and Condensate (per bbl) (b)
 
 
 
Bakken

$39.92

 

$89.46

Eagle Ford
42.72

 
96.10

Oklahoma Resource Basins
45.57

 
94.38

Other North America (c)
41.39

 
89.25

Total Crude Oil and Condensate
41.75

 
92.48

Natural Gas Liquids (per bbl)
 
 
 
Bakken
N.M.

 

$57.62

Eagle Ford
13.73

 
37.50

Oklahoma Resource Basins
17.04

 
44.58

Other North America (c)
26.38

 
61.83

Total Natural Gas Liquids
14.43

 
43.11

Total Liquid Hydrocarbons (per bbl)
 
 
 
Bakken

$37.78

 

$87.60

Eagle Ford
36.30

 
84.16

Oklahoma Resource Basins
28.25

 
58.75

Other North America (c)
40.23

 
87.40

Total Liquid Hydrocarbons
36.92

 
84.79

Natural Gas (per mcf)
 
 
 
Bakken

$2.93

 

$8.41

Eagle Ford
2.88

 
4.89

Oklahoma Resource Basins
2.61

 
5.50

Other North America (c)
3.59

 
5.10

Total Natural Gas
3.01

 
5.28

Benchmarks
 
 
 
WTI crude oil (per bbl)(d)

$48.58

 

$98.62

Louisiana Light Sweet ("LLS") crude oil (per bbl)(e)
52.84

 
104.38

Mont Belvieu NGLs (per bbl) (f)
18.39

 
38.38

Henry Hub natural gas(g) (per mmbtu)(h)  
2.98

 
4.94

(a) 
Excludes gains or losses on derivative instruments.
(b) 
Inclusion of realized gains on crude oil derivative instruments would have increased average crude oil price realization by $0.21 per bbl for the first quarter of 2015. There were no crude oil derivative instruments for the first quarter of 2014.
(c) 
Includes Gulf of Mexico and other conventional onshore U.S. production.
(d) 
NYMEX.
(e) 
Bloomberg Finance LLP: LLS St. James.
(f) 
Bloomberg Finance LLP: Y-grade Mix NGL of 50% ethane, 25% propane, 10% butane, 5% isobutane and 10% natural gasoline.
(g) 
Settlement date average.
(h) 
Million British thermal units.
N.M.
Not meaningful.
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.

22



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 for the first quarter of 2015 and 2014.
 
Three Months Ended March 31,
 
2015
 
2014
Average Price Realizations
 
 
 
Crude Oil and Condensate (per bbl)
 
 
 
Equatorial Guinea
$42.55
 
$90.44
United Kingdom
57.19

 
110.99

Total Crude Oil and Condensate
48.87

 
97.73

Natural Gas Liquids (per bbl)
 
 
 
Equatorial Guinea (a)
$1.00
 
$1.00
United Kingdom
33.64

 
73.10

Total Natural Gas Liquids
3.46

 
4.52

Total Liquid Hydrocarbons (per bbl)
 
 
 
Equatorial Guinea

$27.85

 

$62.37

United Kingdom
55.81

 
109.53

Total Liquid Hydrocarbons
37.31

 
75.55

Natural Gas (per mcf)
 
 
 
Equatorial Guinea (a)

$0.24

 

$0.24

United Kingdom
7.68

 
10.02

Libya

 
6.65

Total Natural Gas
0.78

 
0.92

Benchmark
 
 
 
Brent (Europe) crude oil (per bbl)(b)

$53.92

 

$108.17

(a) 
Primarily represents fixed prices under long-term contracts with Alba Plant LLC, Atlantic Methanol Production Company LLC and Equatorial Guinea LNG Holdings Limited, which are equity method investees.  We include our share of income from each of these equity method investees in our International E&P segment.
(b) 
Average of monthly prices obtained from Energy Information Administration ("EIA") website.
Liquid hydrocarbons – Our United Kingdom ("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.
NGLs in E.G. are subject to fixed-price, term contracts; therefore, our reported average NGL realized prices within the International E&P segment will not fully track market price movements.
Natural gas Our natural gas sales from E.G. are subject to fixed-price, term contracts, making realized prices in this area less volatile; therefore, our reported average natural gas realized prices within the International E&P segment will not fully track market price movements.
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 Western Canadian Select ("WCS"). Comparing the corresponding 2015 and 2014 periods, the WCS discount to WTI narrowed in the first quarter of 2015 by $8.39 per barrel.
The operating cost structure of our Oil Sands Mining operations is predominantly fixed and therefore many of the costs incurred in times of full operation continue during production downtime. Per-unit costs are sensitive to production rates. Key variable costs are natural gas and diesel fuel, which track commodity markets such as the Canadian Alberta Energy Company ("AECO") natural gas sales index and crude oil prices.

23



The following table presents our average price realizations and the related benchmarks that impacted both our revenues and variable costs for the first quarter of 2015 and 2014.
 
Three Months Ended March 31,
 
2015
 
2014
Average Price Realizations
 
 
 
Synthetic Crude Oil (per bbl)

$40.37

 

$88.50

Benchmark
 
 
 
WTI crude oil (per bbl)(a)

$48.58

 

$98.62

WCS crude oil (per bbl)(b) 
$33.90
 
$75.55
AECO natural gas sales index (per mmbtu)(c)
 
$2.09
 
$4.99
(a) 
NYMEX.
(b) 
Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.
(c) 
Monthly average AECO day ahead index.
Results of Operations
Consolidated Results of Operation
Sales and other operating revenues, including related party are presented by segment in the table below:
 
Three Months Ended March 31,
(In millions)
2015
 
2014
Sales and other operating revenues, including related party
 
 
 
North America E&P
$
850

 
$
1,392

International E&P
182

 
380

Oil Sands Mining
225

 
377

Segment sales and other operating revenues, including related party
$
1,257

 
$
2,149

Unrealized gain on crude oil derivative instruments
23

 

Sales and other operating revenues, including related party
$
1,280

 
$
2,149

 
Refer to the preceding Operations and Market Conditions sections for additional detail related to our net sales volumes and average price realizations.
North America E&P sales and other operating revenues decreased 39% in the first quarter of 2015 from the comparable 2014 period primarily due to lower price realizations, partially offset by higher net sales volumes from the U.S. resource plays. See additional detail by product in the table that follows:
 
 
Three Months Ended
 
Increase (Decrease) Related to
 
Three Months Ended
(In millions)
 
March 31, 2014
 
Price Realizations
 
Net Sales Volumes
 
March 31, 2015
North America E&P Price-Volume Analysis
Liquid hydrocarbons
 
$
1,245

 
$
(960
)
 
$
456

 
$
741

Natural gas
 
142

 
(73
)
 
28

 
97

Realized gain on crude oil
 
 
 
 
 
 
 
 
    derivative instruments
 

 
3

 


 
3

Other sales
 
5

 


 


 
9

Total
 
$
1,392

 
 
 
 
 
$
850


24



International E&P sales and other operating revenues decreased 52% in the first quarter of 2015 from the comparable 2014 period. The decrease was due to the lower price realizations and lower net sales volumes as detailed by product in the following table:
 
 
Three Months Ended
 
Increase (Decrease) Related to
 
Three Months Ended
(In millions)
 
March 31, 2014
 
Price Realizations
 
Net Sales Volumes
 
March 31, 2015
International E&P Price-Volume Analysis
Liquid hydrocarbons
 
$
330

 
$
(143
)
 
$
(48
)
 
$
139

Natural gas
 
38

 
(5
)
 
(1
)
 
32

Other sales
 
12

 
 
 
 
 
11

Total
 
$
380

 
 
 
 
 
$
182

Oil Sands Mining sales and other operating revenues decreased 40% in the first quarter of 2015, from the comparable 2014 period primarily due to lower synthetic crude oil price realizations, partially offset by higher net sales volumes. The following table displays changes by product:
 
 
Three Months Ended
 
Increase (Decrease) Related to
 
Three Months Ended
(In millions)
 
March 31, 2014
 
Price Realizations
 
Net Sales Volumes
 
March 31, 2015
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil
 
$
373

 
$
(260
)
 
$
104

 
$
217

Other sales
 
4

 


 


 
8

Total
 
$
377

 
 
 
 
 
$
225


Unrealized gains on crude oil derivative instruments are included in total sales and other operating revenues but are not allocated to the segments. In the first quarter of 2015, the net unrealized gain on crude oil derivative instruments was $23 million. There were no crude oil derivative instruments in the first quarter of 2014.
Marketing revenues decreased $337 million in the first quarter of 2015 from the comparable prior-year period. The decrease is related primarily to lower marketed volumes and the lower commodity price environment in North America. 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. Because the volume of marketing activity is based on market dynamics, it can fluctuate from period to period.
Income from equity method investments decreased $101 million in the first quarter of 2015 from the comparable 2014 period. The decrease in the first quarter of 2015 is primarily due to lower price realizations for Liquified Natural Gas ("LNG") at our LNG facility, Liquified Petroleum Gas ("LPG") at our Alba plant, and lower methanol prices at our AMPCO methanol facility, all of which are located in E.G. Also contributing to this decrease in 2015 were lower sales volumes at the AMPCO methanol facility due to the previously mentioned turnaround.
Production expenses decreased $98 million in the first quarter of 2015 from the first quarter of 2014, primarily due to decreases of $56 million and $33 million in the OSM and International E&P segments, respectively. OSM production expenses decreased primarily as a result of lower feedstock costs and operating expenses, namely contract labor and utilities. International E&P production expenses decreased due to lower repair costs in the first quarter of 2015, versus the previous year which included costs related to reliability issues at the non-operated Foinaven field in the U.K. and non-recurring riser repairs in E.G.

25



The production expense rate (expense per boe) for North America E&P declined due to overall cost reductions and leveraging efficiencies in the first quarter of 2015 as production volumes increased. The expense rate for International E&P declined due to reduced project costs in 2015 as discussed in the preceding paragraph. The OSM expense rate declined as volumes increased while feedstock and operating expenses decreased. OSM utilized less feedstock (at lower prices) and experienced lower contract labor costs as a result of higher mine reliability in 2015. The following table provides production expense rates for each segment:
 
 
Three Months Ended March 31,
($ per boe)
 
2015
 
2014
Production Expense Rate
North America E&P
 

$7.94

 

$11.02

International E&P
 

$6.40

 

$8.76

Oil Sands Mining (a)
 

$34.78

 

$47.54

(a)
Production expense per synthetic crude oil barrel includes production costs, shipping and handling, taxes other than income and insurance costs and excludes pre-development costs.
Marketing costs decreased $337 million in the first quarter of 2015 from the comparable 2014 period, consistent with the marketing revenues changes discussed above.
 Exploration expenses were $17 million higher in the first quarter of 2015 than in the comparable 2014 period primarily due to higher dry well costs, partially offset by lower unproved property impairments. Dry well costs for the first quarter of 2015 include the Sodalita West #1 well in E.G. and the Key Largo well in the Gulf of Mexico, both of which were deemed unsuccessful in early 2015. The first quarter of 2014 included non-cash unproved property impairments related to Eagle Ford and Bakken leases that either had expired or that we did not expect to drill or extend. The following table summarizes the components of exploration expenses:
 
 
Three Months Ended March 31,
(In millions)
 
2015
 
2014
Exploration Expenses
Unproved property impairments
 
$
9

 
$
41

Dry well costs
 
58

 
2

Geological and geophysical
 
3

 
11

Other
 
20

 
19

Total exploration expenses
 
$
90

 
$
73

Depreciation, depletion and amortization (“DD&A”) increased $178 million in the first quarter of 2015 from the comparable 2014 period primarily as a result of higher North America E&P net sales volumes from our three U.S. resource plays, partially offset by lower International E&P net sales volumes as previously discussed.  Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, volumes have an impact on DD&A expense.
The DD&A rate (expense per boe), which is impacted by field-level changes sales volumes, reserves and capitalized costs, can also cause changes to our DD&A.
 
 
Three Months Ended March 31,
($ per boe)
 
2015
 
2014
DD&A Rate
 
 

 
 

North America E&P
 

$26.85

 

$26.88

International E&P
 

$6.10

 

$6.25

Oil Sands Mining