10-Q


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
FORM 10-Q
(Mark One)
 
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the Quarterly Period Ended September 30, 2015
OR
[   ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period 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 677,260,116 shares of Marathon Oil Corporation common stock outstanding as of October 31, 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).
For certain industry specific terms used in this Form 10-Q, please see "Definitions" in our 2014 Annual Report on Form 10-K.

 
Table of Contents
 
 
 
Page
 
 
 
 
 
 
 
 
 
 


1


Part I - Financial Information
Item 1. Financial Statements

MARATHON OIL CORPORATION
Consolidated Statements of Income (Unaudited)
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
(In millions, except per share data)
2015
 
2014
 
2015
 
2014
Revenues and other income:
 
 
 
 
 
 
 
Sales and other operating revenues, including related party
$
1,300

 
$
2,316

 
$
3,887

 
$
6,735

Marketing revenues
84

 
554

 
471

 
1,713

Income from equity method investments
36

 
89

 
98

 
346

Net loss on disposal of assets
(109
)
 
(3
)
 
(108
)
 
(88
)
Other income
12

 
15

 
38

 
55

Total revenues and other income
1,323

 
2,971

 
4,386

 
8,761

Costs and expenses:
 

 
 

 
 
 
 

Production
406

 
593

 
1,300

 
1,697

Marketing, including purchases from related parties
84

 
554

 
471

 
1,710

Other operating
93

 
99

 
281

 
303

Exploration
585

 
96

 
786

 
314

Depreciation, depletion and amortization
717

 
737

 
2,289

 
2,060

Impairments
337

 
109

 
381

 
130

Taxes other than income
46

 
115

 
191

 
319

General and administrative
125

 
160

 
464

 
486

Total costs and expenses
2,393

 
2,463

 
6,163

 
7,019

Income (loss) from operations
(1,070
)
 
508

 
(1,777
)
 
1,742

Net interest and other
(75
)
 
(55
)
 
(180
)
 
(180
)
Income (loss) from continuing operations before income taxes
(1,145
)
 
453

 
(1,957
)
 
1,562

Provision (benefit) for income taxes
(396
)
 
149

 
(546
)
 
500

Income (loss) from continuing operations
(749
)
 
304

 
(1,411
)
 
1,062

Discontinued operations
—

 
127

 
—

 
1,058

Net income (loss)
$
(749
)
 
$
431

 
$
(1,411
)
 
$
2,120

Per basic share:
 

 
 

 
 

 
 

Income (loss) from continuing operations
$
(1.11
)
 
$
0.45

 
$
(2.09
)
 
$
1.56

Discontinued operations
$
—

 
$
0.19

 
$
—

 
$
1.55

Net income (loss)
$
(1.11
)
 
$
0.64

 
$
(2.09
)
 
$
3.11

Per diluted share:
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(1.11
)
 
$
0.45

 
$
(2.09
)
 
$
1.55

Discontinued operations
$
—

 
$
0.19

 
$
—

 
$
1.55

Net income (loss)
$
(1.11
)
 
$
0.64

 
$
(2.09
)
 
$
3.10

Dividends per share
$
0.21

 
$
0.21

 
$
0.63

 
$
0.59

Weighted average common shares outstanding:
 

 
 

 
 

 
 

Basic
677

 
675

 
677

 
681

Diluted
677

 
678

 
677

 
684

 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
 
Nine Months Ended
 
September 30,
 
September 30,
(In millions)
2015
 
2014
 
2015
 
2014
Net income (loss)
$
(749
)
 
$
431

 
$
(1,411
)
 
$
2,120

Other comprehensive income (loss)
 

 
 

 
 

 
 

Postretirement and postemployment plans
 

 
 

 
 

 
 

Change in actuarial loss and other
(2
)
 
3

 
160

 
(40
)
Income tax benefit (provision)
(1
)
 
(2
)
 
(58
)
 
13

Postretirement and postemployment plans, net of tax
(3
)
 
1

 
102

 
(27
)
Comprehensive income (loss)
$
(752
)
 
$
432

 
$
(1,309
)
 
$
2,093

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


3


MARATHON OIL CORPORATION
Consolidated Balance Sheets (Unaudited)
 
September 30,
 
December 31,
(In millions, except per share data)
2015
 
2014
Assets
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
1,680

 
$
2,398

Short-term investments
700

 
—

Receivables, less reserve of $4 and $3
991

 
1,729

Inventories
324

 
357

Other current assets
163

 
109

Total current assets
3,858

 
4,593

Equity method investments
1,012

 
1,113

Property, plant and equipment, less accumulated depreciation,
 

 
 

depletion and amortization of $23,713 and $21,884
27,920

 
29,040

Goodwill
457

 
459

Other noncurrent assets
1,427

 
806

Total assets
$
34,674

 
$
36,011

Liabilities
 

 
 

Current liabilities:
 

 
 

Accounts payable
$
1,246

 
$
2,545

Payroll and benefits payable
138

 
191

Accrued taxes
143

 
285

Other current liabilities
286

 
290

Long-term debt due within one year
1,035

 
1,068

Total current liabilities
2,848

 
4,379

Long-term debt
7,323

 
5,323

Deferred tax liabilities
2,542

 
2,486

Defined benefit postretirement plan obligations
436

 
598

Asset retirement obligations
1,965

 
1,917

Deferred credits and other liabilities
225

 
288

Total liabilities
15,339

 
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 – 93 million and 95 million shares
(3,553
)
 
(3,642
)
Additional paid-in capital
6,493

 
6,531

Retained earnings
15,800

 
17,638

Accumulated other comprehensive loss
(175
)
 
(277
)
Total stockholders' equity
19,335

 
21,020

Total liabilities and stockholders' equity
$
34,674

 
$
36,011

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

4


MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows (Unaudited)
 
Nine Months Ended
 
September 30,
(In millions)
2015
 
2014
Increase (decrease) in cash and cash equivalents
 
 
 
Operating activities:
 

 
 

Net income (loss)
$
(1,411
)
 
$
2,120

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

 
 

Discontinued operations
—

 
(1,058
)
Deferred income taxes
(590
)
 
337

Depreciation, depletion and amortization
2,289

 
2,060

Impairments
381

 
130

Pension and other postretirement benefits, net
9

 
(27
)
Exploratory dry well costs and unproved property impairments
708

 
220

Net loss on disposal of assets
108

 
88

Equity method investments, net
41

 
51

Changes in:
 
 
 

Current receivables
738

 
(270
)
Inventories
30

 
(32
)
Current accounts payable and accrued liabilities
(954
)
 
(115
)
All other operating, net
(136
)
 
(28
)
Net cash provided by continuing operations
1,213

 
3,476

Net cash provided by discontinued operations
—

 
856

Net cash provided by operating activities
1,213

 
4,332

Investing activities:
 

 
 

Acquisitions, net of cash acquired
—

 
(12
)
Additions to property, plant and equipment
(2,948
)
 
(3,639
)
Disposal of assets
105

 
2,237

Investments - return of capital
61

 
46

Purchases of short-term investments
(925
)
 
—

Maturities of short-term investments
225

 
—

Investing activities of discontinued operations
—

 
(356
)
All other investing, net
22

 
(24
)
Net cash used in investing activities
(3,460
)
 
(1,748
)
Financing activities:
 

 
 

Commercial paper, net
—

 
(135
)
Borrowings
1,996

 
—

Debt issuance costs
(19
)
 
—

Debt repayments
(34
)
 
(34
)
Purchases of common stock
—

 
(1,000
)
Dividends paid
(427
)
 
(401
)
All other financing, net
14

 
150

Net cash provided by (used in) financing activities
1,530

 
(1,420
)
Effect of exchange rate on cash and cash equivalents:
 
 
 
Continuing operations
(1
)
 
(1
)
Discontinued operations
—

 
(11
)
Cash held for sale
—

 
(655
)
Net increase (decrease) in cash and cash equivalents
(718
)
 
497

Cash and cash equivalents at beginning of period
2,398

 
264

Cash and cash equivalents at end of period
$
1,680

 
$
761

 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.
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 our 2014 Annual Report on Form 10-K.  The results of operations for the third quarter and first nine months of 2015 are not necessarily indicative of the results to be expected for the full year.
2.   Accounting Standards
Not Yet 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 will be applied on a retrospective basis. Early adoption is permitted. This standard only modifies disclosure requirements; as such, there will be no impact on our consolidated results of operations, financial position or cash flows.
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. 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 by which a reporting entity assesses whether the equity holders at risk lack decision making rights if the decision-making over the subject entity’s most significant activities was outsourced. This standard is effective for us in the first quarter of 2016 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 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 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 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 with an effective date no earlier than first quarter of 2017. 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.

6

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


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.
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 September 30, 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 $471 million as of September 30, 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 per share assumes exercise of stock options, provided the effect is not antidilutive. The per share calculations below exclude 13 million and 2 million stock options for the third quarters of 2015 and 2014 and 13 million and 4 million stock options for the first nine months of 2015 and 2014 that were antidilutive.
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(In millions, except per share data)
2015
 
2014
 
2015
 
2014
Income (loss) from continuing operations
$
(749
)
 
$
304

 
$
(1,411
)
 
$
1,062

Discontinued operations
—

 
127

 
—

 
1,058

Net income (loss)
$
(749
)
 
$
431

 
$
(1,411
)
 
$
2,120

 
 
 
 
 
 
 
 
Weighted average common shares outstanding
677

 
675

 
677

 
681

Effect of dilutive securities
—

 
3

 
—

 
3

Weighted average common shares, diluted
677

 
678

 
677

 
684

Per basic share:
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(1.11
)
 
$
0.45

 
$
(2.09
)
 
$
1.56

Discontinued operations
$
—

 
$
0.19

 
$
—

 
$
1.55

Net income (loss)
$
(1.11
)
 
$
0.64

 
$
(2.09
)
 
$
3.11

Per diluted share:
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(1.11
)
 
$
0.45

 
$
(2.09
)
 
$
1.55

Discontinued operations
$
—

 
$
0.19

 
$
—

 
$
1.55

Net income (loss)
$
(1.11
)
 
$
0.64

 
$
(2.09
)
 
$
3.10


7

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


5.
Acquisitions
2014 - North America E&P Segment
In the third quarter of 2014, we acquired acreage in the Oklahoma Resource Basins at a cost of $68 million after final settlement adjustments.
6.
Dispositions
2015 - North America E&P Segment
In August 2015, we closed the sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets for proceeds of approximately $100 million and recorded a pretax loss of $1 million. During the second quarter of 2015, we recorded a non-cash impairment charge of $44 million related to these assets (See Note 15).
2015 - International E&P Segment
In September 2015, we entered into an agreement to sell our East Africa exploration acreage in Ethiopia and Kenya. A pretax loss of $109 million was recorded in the third quarter of 2015. This transaction is expected to close during the fourth quarter of 2015.
2014 - North America E&P Segment
In the second quarter of 2014, we closed the sale of non-core acreage located in the far northwest portion of Williston Basin for proceeds of $90 million and recorded a pretax loss of $91 million.
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 were as follows:
 
Three Months Ended September 30,
Nine Months Ended September 30,
 
(In millions)
 
2014
 
2014
 
Revenues applicable to discontinued operations
 
$
528

 
$
1,901

 
Pretax income from discontinued operations
 
$
487

 
$
1,617

 
After-tax income from discontinued operations
 
$
127

 
$
449

(a) 
(a)    Includes a tax benefit of $26 million related to a decrease in the valuation allowance on U.S. foreign tax credits from the Norway operations.
 
 
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 were as follows:
 
Nine Months Ended September 30,
(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

 
 

8

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


7.    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.
•
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 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, change in tax expense associated with a tax rate change, unrealized gains or losses on crude oil derivative instruments, or other items that affect comparability also are not allocated to operating segments.
As discussed in Note 6, 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 Int'l E&P segment for 2014.
 
Three Months Ended September 30, 2015
 
 
 
Not Allocated
 
 
(In millions)
N.A. E&P
 
Int'l E&P
 
OSM
 
to Segments
 
Total
Sales and other operating revenues
$
796

 
$
182

 
$
242

 
$
80

(c) 
$
1,300

Marketing revenues
57

 
25

 
2

 
—

 
84

Total revenues
853

 
207

 
244

 
80

 
1,384

Income (loss) from equity method investments
—

 
48

 
—

 
(12
)
(d) 
36

Net gain (loss) on disposal of assets and other income
6

 
6

 
—

 
(109
)
(e) 
(97
)
Less:
 
 
 
 
 
 
 
 
 
Production expenses
179

 
61

 
166

 
—

 
406

Marketing costs
56

 
25

 
3

 
—

 
84

Exploration expenses
22

 
10

 
—

 
553

(f) 
585

Depreciation, depletion and amortization
549

 
79

 
76

 
13

 
717

Impairments
—

 
—

 
4

 
333

(g) 
337

Other expenses (a)
106

 
25

 
8

 
79

(h) 
218

Taxes other than income
42

 
—

 
5

 
(1
)
 
46

Net interest and other
—

 
—

 
—

 
75

 
75

Income tax provision (benefit)
(34
)
 
32

 
(7
)
 
(387
)
 
(396
)
Segment income (loss) /Loss from continuing operations
$
(61
)
 
$
29

 
$
(11
)
 
$
(706
)
 
$
(749
)
Capital expenditures (b)
$
564

 
$
30

 
$
(11
)
 
$
12

 
$
595

(a) 
Includes other operating expenses and general and administrative expenses.
(b) 
Includes accruals.
(c) 
Unrealized gain on crude oil derivative instruments.
(d) 
Partial impairment of investment in equity method investee (See Note 15).
(e) 
Includes loss on sale of East Africa exploration acreage (See Note 6).
(f) 
Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (See Note 14).
(g) 
Proved property impairments (See Note 14).
(h) 
Includes pension settlement loss of $18 million and severance related expenses associated with workforce reductions of $4 million (See Note 8).


9

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


 
Three Months Ended September 30, 2014
 
 
 
Not Allocated
 
 
(In millions)
N.A. E&P
 
Int'l E&P
 
OSM
 
to Segments
 
Total
Sales and other operating revenues
$
1,586

 
$
273

 
$
457

 
$
—

 
$
2,316

Marketing revenues
506

 
46

 
2

 
—

 
554

Total revenues
2,092

 
319

 
459

 
—

 
2,870

Income from equity method investments
—

 
89

 
—

 
—

 
89

Net gain (loss) on disposal of assets and other income
(1
)
 
12

 
—

 
1

 
12

Less:
 
 
 
 
 
 
 
 
 
Production expenses
233

 
108

 
252

 
—

 
593

Marketing costs
507

 
45

 
2

 
—

 
554

Exploration expenses
55

 
41

 
—

 
—

 
96

Depreciation, depletion and amortization
609

 
55

 
62

 
11

 
737

Impairments
—

 
—

 
—

 
109

(c) 
109

Other expenses (a)
118

 
26

 
14

 
101

(d) 
259

Taxes other than income
109

 
—

 
5

 
1

 
115

Net interest and other
—

 
—

 
—

 
55

 
55

Income tax provision (benefit)
168

 
39

 
31

 
(89
)
 
149

Segment income/Income from continuing operations
$
292

 
$
106

 
$
93

 
$
(187
)
 
$
304

Capital expenditures (b)
$
1,277

 
$
166

 
$
49

 
$
16

 
$
1,508

(a) 
Includes other operating expenses and general and administrative expenses.
(b) 
Includes accruals.
(c) 
Proved property impairment (See Note 14).
(d) 
Includes pension settlement loss of $22 million (See Note 8).
 
Nine Months Ended September 30, 2015
 
 
 
Not Allocated
 
 
(In millions)
N.A. E&P
 
Int'l E&P
 
OSM
 
to Segments
 
Total
Sales and other operating revenues
$
2,639

 
$
575

 
$
614

 
$
59

(c) 
$
3,887

Marketing revenues
345

 
81

 
45

 
—

 
471

Total revenues
2,984

 
656

 
659

 
59

 
4,358

Income (loss) from equity method investments
—

 
110

 
—

 
(12
)
(d) 
98

Net gain (loss) on disposal of assets and other income
17

 
20

 
1

 
(108
)
(e) 
(70
)
Less:
 
 
 
 
 
 
 
 
 
Production expenses
560

 
192

 
548

 
—

 
1,300

Marketing costs
348

 
79

 
44

 
—

 
471

Exploration expenses
148

 
85

 
—

 
553

(f) 
786

Depreciation, depletion and amortization
1,866

 
214

 
173

 
36

 
2,289

Impairments
—

 
—

 
4

 
377

(g) 
381

Other expenses (a)
322

 
67

 
26

 
330

(h) 
745

Taxes other than income
170

 
—

 
15

 
6

 
191

Net interest and other
—

 
—

 
—

 
180

 
180

Income tax provision (benefit)
(146
)
 
56

 
(43
)
 
(413
)
(i) 
(546
)
Segment income (loss) /Loss from continuing operations
$
(267
)
 
$
93

 
$
(107
)
 
$
(1,130
)
 
$
(1,411
)
Capital expenditures (b)
$
2,048

 
$
275

 
$
26

 
$
26

 
$
2,375

(a) 
Includes other operating expenses and general and administrative expenses.
(b) 
Includes accruals.
(c) 
Unrealized gain on crude oil derivative instruments.
(d) 
Partial impairment of investment in equity-method investee (See Note 15).
(e) 
Includes loss on sale of East Africa exploration acreage (See Note 6).
(f) 
Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (See Note 14).
(g) 
Proved property impairments (See Note 14).
(h) 
Includes pension settlement loss of $99 million and severance related expenses associated with workforce reductions of $47 million (See Note 8).
(i) 
Includes $135 million of deferred tax expense related to Alberta provincial corporate tax rate increase (See Note 9).


10

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



 
Nine Months Ended September 30, 2014
 
 
 
Not Allocated
 
 
(In millions)
N.A. E&P
 
Int'l E&P
 
OSM
 
to Segments
 
Total
Sales and other operating revenues
$
4,518

 
$
1,000

 
$
1,217

 
$
—

 
$
6,735

Marketing revenues
1,486

 
177

 
50

 
—

 
1,713

Total revenues
6,004

 
1,177

 
1,267

 
—

 
8,448

Income from equity method investments
—

 
346

 
—

 
—

 
346

Net gain (loss) on disposal of assets and other income
17

 
44

 
3

 
(97
)
(c) 
(33
)
Less:
 
 
 
 
 
 
 
 
 
Production expenses
661

 
307

 
729

 
—

 
1,697

Marketing costs
1,484

 
176

 
50

 
—

 
1,710

Exploration expenses
194

 
120

 
—

 
—

 
314

Depreciation, depletion and amortization
1,674

 
201

 
152

 
33

 
2,060

Impairments
21

 
—

 
—

 
109

(d) 
130

Other expenses (a)
354

 
98

 
40

 
297

(e) 
789

Taxes other than income
301

 
—

 
16

 
2

 
319

Net interest and other
—

 
—

 
—

 
180

 
180

Income tax provision (benefit)
496

 
178

 
71

 
(245
)
 
500

Segment income /Income from continuing operations
$
836

 
$
487

 
$
212

 
$
(473
)
 
$
1,062

Capital expenditures (b)
$
3,246

 
$
386

 
$
172

 
$
29

 
$
3,833

(a) 
Includes other operating expenses and general and administrative expenses.
(b) 
Includes accruals.
(c) 
Primarily related to the sale of non-core acreage (See Note 6).
(d) 
Proved property impairments (See Note 14).
(e) 
Includes pension settlement loss of $93 million (See Note 8).
8.    Defined Benefit Postretirement Plans
The following summarizes the components of net periodic benefit cost:
 
Three Months Ended September 30,
  
Pension Benefits
 
Other Benefits
(In millions)
2015
 
2014
 
2015
 
2014
Service cost
$
11

 
$
12

 
$
—

 
$
—

Interest cost
12

 
15

 
3

 
4

Expected return on plan assets
(17
)
 
(16
)
 
—

 
—

Amortization:
 

 
 

 
 

 
 

– prior service cost (credit)
(3
)
 
1

 
(1
)
 
(1
)
– actuarial loss
5

 
7

 
1

 
—

Net settlement loss (a)
18

 
22

 
—

 
—

Net curtailment loss (b)
4

 
—

 
—

 
—

Net periodic benefit cost
$
30

 
$
41

 
$
3

 
$
3


11

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


 
Nine Months Ended September 30,
  
Pension Benefits
 
Other Benefits
(In millions)
2015
 
2014
 
2015
 
2014
Service cost
$
35

 
$
35

 
$
2

 
$
2

Interest cost
39

 
46

 
8

 
10

Expected return on plan assets
(53
)
 
(48
)
 
—

 
—

Amortization:
 

 
 

 
 

 
 

– prior service cost (credit)
(4
)
 
4

 
(3
)
 
(3
)
– actuarial loss
19

 
23

 
1

 
—

Net settlement loss(a)
99

 
93

 
—

 
—

Net curtailment loss (gain) (b)
5

 
—

 
(4
)
 
—

Net periodic benefit cost
$
140


$
153


$
4


$
9

(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 and the impact of discontinuing accruals for future benefits under the U.K. pension plan effective December 31, 2015.
During the first nine months of 2015, we recorded the effects of a workforce reduction, a U.S. pension plan amendment and the discontinuation of accruals for future benefits under the U.K. pension plan. The U.S. pension plan amendment freezes the final average pay used to calculate the benefit under the legacy final average pay formula and was effective July 6, 2015. For the U.K. pension plan, a final decision was reached with the plan trustees to close the plan to future benefit accruals effective December 31, 2015. Additionally, during the first nine months of 2015 and 2014, 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 nine months of 2015, we made contributions of $65 million to our funded pension plans.  We expect to make additional contributions up to an estimated $18 million to our funded pension plans over the remainder of 2015.  During the first nine months of 2015, we made payments of $57 million and $13 million related to unfunded pension plans and other postretirement benefit plans, respectively.
9.    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 (benefit) and the sum of the amounts allocated to segments is reported in the “Not Allocated to Segments” column of the tables in Note 7.
Our effective income tax rates on continuing operations for the first nine months of 2015 and 2014 were 28% and 32%.  The tax provision (benefit) applicable to Libyan ordinary income (loss) was recorded as a discrete item in the first nine months of 2015 and 2014.  Excluding Libya, the effective tax rates on continuing operations, would be 27% and 32% for the first nine months of 2015 and 2014. In Libya, uncertainty remains 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 nine months of 2015 and 2014, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss).
Change in Tax Law
On June 29, 2015, the Alberta government enacted legislation to increase the provincial corporate tax rate from 10% to 12%. As a result of this legislation, we recorded additional non-cash deferred tax expense of $135 million in the second quarter of 2015.
Indefinite Reinvestment Assertion
In the second quarter of 2015, we reviewed our operations and concluded that we do not have the same level of capital needs outside the U.S. as previously expected. Therefore, we no longer intend for previously unremitted foreign earnings of

12

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


approximately $1 billion associated with our Canadian operations to be permanently reinvested outside the U.S. As such, none of Marathon Oil’s foreign earnings remain permanently reinvested abroad. We anticipate foreign tax credits associated with these Canadian earnings would be sufficient to offset any incremental U.S. tax liabilities, and therefore, no additional net deferred taxes were recorded in the second quarter of 2015.
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.

10.    Short-term Investments
As of September 30, 2015, our short-term investments are comprised of bank time deposits with original maturities of greater than three months and remaining maturities of less than twelve months. They are classified as held-to-maturity investments, which are recorded at amortized cost. The carrying values of our short-term investments approximate fair value. These short-term investments matured during October 2015.
11.   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.
 
September 30,
 
December 31,
(In millions)
2015
 
2014
Liquid hydrocarbons, natural gas and bitumen
$
39

 
$
58

Supplies and other items
285

 
299

Inventories, at cost
$
324

 
$
357

12.  Property, Plant and Equipment, net of Accumulated Depreciation, Depletion and Amortization
 
September 30,
 
December 31,
(In millions)
2015
 
2014
North America E&P
$
15,875

 
$
16,717

International E&P
2,604

 
2,741

Oil Sands Mining
9,334

 
9,455

Corporate
107

 
127

Net property, plant and equipment
$
27,920


$
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 September 30, 2015, our net property, plant and equipment investment in Libya is $775 million, and total proved reserves (unaudited) in Libya as of December 31, 2014 are 243 million boe. 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 $775 million by a material amount.
Exploratory well costs capitalized greater than one year after completion of drilling were $88 million and $126 million as of September 30, 2015 and December 31, 2014. This $38 million net decrease was associated with a write-down of our Canadian in-situ assets at Birchwood in the second quarter of 2015. After further evaluation of the estimated recoverable

13

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


resources and our development plans, we withdrew our regulatory application for the proposed steam assisted gravity drainage demonstration project at Birchwood.
13. Other Noncurrent Assets
 
September 30,
 
December 31,
(in millions)
2015
 
2014
Deferred tax assets
$
1,115

 
$
525

Intangible assets
95

 
96

Other
217

 
185

Other noncurrent assets
$
1,427

 
$
806

14. Impairments and Exploration Expenses
The continued decline of commodity prices resulted in a downward revision of our long-term commodity price assumptions and was a triggering event which required us to reassess long-lived assets related to oil and gas producing properties for impairment as of September 30, 2015. Further changes in management's forecast assumptions may cause us to reassess our long-lived assets for impairment, and could result in non-cash impairment charges in the future.
The following table summarizes impairment charges of proved properties:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in millions)
2015
 
2014
 
2015
 
2014
Total impairments
$
337

 
$
109

 
$
381

 
$
130

Impairments for the three and nine months ended September 30, 2015 consisted primarily of proved properties in Colorado and the Gulf of Mexico as a result of lower forecasted commodity prices.
Impairments for the three and nine months ended September 30, 2014 consisted primarily of proved properties in the Gulf of Mexico, Texas and North Dakota as a result of revisions to estimated abandonment costs and lower forecasted commodity prices. See Note 7 for relevant detail regarding segment presentation and Note 15 for fair value measurements related to impairments of proved properties.
The following table summarizes the components of exploration expenses:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(In millions)
2015
 
2014
 
2015
 
2014
Exploration Expenses
 
 
 
 
 
 
 
Unproved property impairments
$
563

 
$
39

 
$
612

 
$
140

Dry well costs
(3
)
 
25

 
96

 
80

Geological and geophysical
8

 
10

 
23

 
27

Other
17

 
22

 
55

 
67

Total exploration expenses
$
585

 
$
96

 
$
786

 
$
314

Included in the unproved property impairments for the three and nine months ended September 30, 2015 are non-cash charges of $553 million as a result of changes in our conventional exploration strategy (Gulf of Mexico and Harir block in the Kurdistan Region of Iraq) and lower forecasted commodity prices (Colorado).
Unproved property impairments for the three and nine months ended September 30, 2014 primarily consist of leases in Texas and North Dakota that either expired or we decided not to drill or extend. See Note 7 for relevant detail regarding segment presentation.

14

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


15.  Fair Value Measurements
 Fair Values - Recurring
The following tables present assets and liabilities accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014 by fair value hierarchy level.
 
September 30, 2015
(In millions)
Level 1
 
Level 2
 
Level 3
 
Total
Derivative instruments, assets
 
 
 
 
 
 
 
     Commodity (a)
$
—

 
$
61

 
$
—

 
$
61

     Interest rate
—

 
15

 
—

 
15

Derivative instruments, assets
$
—

 
$
76

 
$
—

 
$
76

Derivative instruments, liabilities
 
 
 
 
 
 
 
     Commodity (a)
$
—

 
$
3

 
$
—

 
$
3

Derivative instruments, liabilities
$
—

 
$
3

 
$
—

 
$
3

(a)  
Derivative instruments are recorded on a net basis in the company's balance sheet (see Note 16).
 
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, swaptions, extendable three-way collars and call options. These instruments are measured at fair value using either the Black-Scholes Model or 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 16 for additional discussion of the types of derivative instruments we use.
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 September 30,
 
2015
 
2014
(In millions)
Fair Value
 
Impairment
 
Fair Value
 
Impairment
Long-lived assets held for use
$
41

 
$
337

 
$
43

 
$
109

 
Nine Months Ended September 30,
 
2015
 
2014
(In millions)
Fair Value
 
Impairment
 
Fair Value
 
Impairment
Long-lived assets held for use
$
58

 
$
381

 
$
43

 
$
130


Commodity prices began declining in the second half of 2014 and remain substantially lower through 2015. The prolonged decline in commodity prices, and the resulting change in management's future commodity price assumptions, was a triggering event which required us to reassess long-lived assets related to oil and gas producing properties for impairment as of September 30, 2015. Further changes in management's forecast assumptions may cause us to reassess our long-lived assets for impairment, and could result in non-cash impairment charges in the future. Long-lived assets held for use that were impaired are discussed below. The fair values of each were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs, unless otherwise noted.  Inputs to the fair value measurement include reserve and production estimates made by our reservoir engineers, estimated future commodity prices

15

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


adjusted for quality and location differentials, and forecasted operating expenses for the remaining estimated life of the reservoir.
2015 - North America E&P
In the third quarter of 2015, impairments of $333 million were recorded primarily related to certain producing assets in Colorado and the Gulf of Mexico as a result of lower forecasted commodity prices, to an aggregate fair value of $41 million.
    During the second quarter of 2015, we recorded a non-cash impairment charge of $44 million related to our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets as a result of the anticipated sale (see Note 6). The fair values were measured using a probability weighted income approach based on both the anticipated sales price and a held-for-use model.
2015 - International E&P    
In the third quarter of 2015, a partial impairment of $12 million was recorded to an investment in an equity method investee as a result of lower forecasted commodity prices, to a fair value of $604 million. This impairment was reflected in income from equity method investments in our consolidated statements of income.
2014 - North America E&P
The Ozona development in the Gulf of Mexico ceased producing in 2013, at which time those long-lived assets were fully impaired. In the first nine months of 2014, we recorded additional impairments of $30 million as a result of estimated abandonment cost revisions.
In the third quarter of 2014, impairments of $53 million were recorded to certain other Gulf of Mexico properties as a result of estimated abandonment cost and other revisions, to an aggregate fair value of $19 million. In addition, two additional on-shore fields were impaired a total of $47 million to an aggregate fair value of $24 million primarily due to lower forecasted commodity prices.
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. After we performed our annual goodwill impairment test in April 2015, a triggering event (downward revision of forecasted commodity price assumptions) required us to reassess our goodwill for impairment as of September 30, 2015. Based on the results of this assessment, we concluded no impairment was required. The fair value of the North America E&P and International E&P reporting units exceeded their respective book values by a significant margin. Changes in management's forecast commodity price assumptions 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, short-term investments, long-term debt due within one year, and payables. We believe the carrying values of our receivables, short-term investments 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.

16

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


The following table summarizes financial instruments, excluding receivables, short-term investments, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at September 30, 2015 and December 31, 2014.
 
September 30, 2015
 
December 31, 2014
 
Fair
 
Carrying
 
Fair
 
Carrying
(In millions)
Value
 
Amount
 
Value
 
Amount
Financial assets
 
 
 
 
 
 
 
Other noncurrent assets
$
109

 
$
116

 
$
132

 
$
129

Total financial assets  
109

 
116

 
132

 
129

Financial liabilities
 

 
 

 
 

 
 

     Other current liabilities
15

 
14

 
13

 
13

     Long-term debt, including current portion (a)
8,302

 
8,324

 
6,887

 
6,360

Deferred credits and other liabilities
69

 
64

 
69

 
68

Total financial liabilities  
$
8,386

 
$
8,402

 
$
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.
16. Derivatives
For further information regarding the fair value measurement of derivative instruments, see Note 15. 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 as of September 30, 2015 and December 31, 2014.
 
September 30, 2015
 
 
(In millions)
Asset
 
Liability
 
Net Asset
 
Balance Sheet Location
Fair Value Hedges
 
 
 
 
 
 
 
     Interest rate
$
15

 
$
—

 
$
15

 
Other noncurrent assets
Total Designated Hedges
15

 
—

 
15

 
 
 
 
 
 
 
 
 
 
Not Designated as Hedges
 
 
 
 
 
 
 
     Commodity
55

 
2

 
53

 
Other current assets
     Commodity
6

 
1

 
5

 
Other noncurrent assets
Total Not Designated as Hedges
61

 
3

 
58

 
 
     Total
$
76


$
3


$
73

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

 
$
—

 
$
8

 
Other noncurrent assets
     Total
$
8

 
$
—

 
$
8

 
 

17

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Derivatives Designated as Fair Value Hedges
The following table presents, by maturity date, information about our interest rate swap agreements as of September 30, 2015 and December 31, 2014, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.
 
September 30, 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

4.68
%
 
$
600

4.64
%
March 15, 2018
$
300

4.54
%
 
$
300

4.49
%
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 September 30,
 
Nine Months Ended September 30,
(In millions)
Income Statement Location
2015
 
2014
 
2015
 
2014
Derivative
 
 
 
 
 
 
 
 
Interest rate
Net interest and other
$
4

 
$
(6
)
 
$
7

 
$
(3
)
Foreign currency
Discontinued operations
$
—

 
$
(18
)
 
$
—

 
$
(29
)
Hedged Item
 
 

 
 

 
 

 
 

Long-term debt
Net interest and other
$
(4
)
 
$
6

 
$
(7
)
 
$
3

Accrued taxes
Discontinued operations
$
—

 
$
18

 
$
—

 
$
29

 Derivatives not Designated as Hedges
During the first nine months of 2015, we entered into multiple crude oil derivatives indexed to New York Mercantile Exchange ("NYMEX") WTI related to a portion of our forecasted North America E&P sales through December 2016. These commodity derivatives consist of three-way collars, extendable three-way collars and call options. 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 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 NYMEX 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:

18

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Financial Instrument
Weighted Average Price
Barrels per day
Remaining Term
Three-Way Collars
 
 
 
Ceiling
$70.34
35,000
October- December 2015
Floor
$55.57
 
 
Sold put
$41.29
 
 
 
 
 
 
Ceiling
$60.00
2,000
October 2015- March 2016 (a)
Floor
$50.00
 
 
Sold put
$40.00
 
 
 
 
 
 
Ceiling
$71.84
12,000
       January- December 2016
Floor
$60.48
 
 
Sold put
$50.00
 
 
 
 
 
 
Ceiling
$73.13
2,000
January- June 2016 (b)
Floor
$65.00
 
 
Sold put
$50.00
 
 
Call Options 
$72.39
10,000
January- December 2016 (c)
(a) 
Counterparties have the option, exercisable on March 31, 2016, to extend these collars through September of 2016 at the same volume and weighted average price as the underlying three-way collars.
(b) 
Counterparty has the option, exercisable on June 30, 2016, to extend these collars through the remainder of 2016 at the same volume and weighted average price as the underlying three-way collars.
(c) 
Call options settle monthly.
The impact of these crude oil derivative instruments appears in sales and other operating revenues in our consolidated statements of income and was a net gain of $108 million and $91 million in the third quarter and first nine months 2015. There were no crude oil derivative instruments in the first nine months of 2014.
On June 1, 2015, we entered into Treasury rate locks, which expired on the same day, to hedge against timing differences as it related to our Notes offering (see Note 18). Following the execution of the Treasury locks, corresponding interest rates increased during the day of June 1. As a result, the settlement of the Treasury rate locks resulted in a gain of $6 million, which was recognized in net interest and other in our consolidated statements of income.
17.    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 nine 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

 
2,674,987

 

$30.52

Options Exercised/Stock Vested
(549,926
)
 

$16.84

 
(1,135,635
)
 

$33.25

Canceled
(605,760
)
 

$34.11

 
(708,380
)
 

$33.20

Outstanding at September 30, 2015
12,996,232

 

$29.99

 
4,279,325

 

$32.17

(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 nine months of 2015, we granted 382,335 stock-based performance units to certain officers. The grant date fair value per unit was $31.77.

19

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


18.  Debt
Revolving Credit Facility As of September 30, 2015, we had no borrowings against our revolving credit facility (as amended, the "Credit Facility"), as described below.
In May 2015, we amended our $2.5 billion unsecured Credit Facility to increase the facility size by $500 million to a total of $3 billion and extended the maturity date by an additional year such that the Credit Facility now matures in May 2020.  The amendment additionally provides us the ability to request two one-year extensions to the maturity date and an option to increase the commitment amount by up to an additional $500 million, subject to the consent of any increasing lenders.  The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively.  Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unchanged.
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 September 30, 2015, we were in compliance with this covenant with a debt-to-capitalization ratio of 30%.
Debt Issuance On June 10, 2015, we issued $2 billion aggregate principal amount of unsecured senior notes which consist of the following series:
•$600 million of 2.70% senior notes due June 1, 2020
•$900 million of 3.85% senior notes due June 1, 2025
•$500 million of 5.20% senior notes due June 1, 2045
Interest on each series of senior notes is payable semi-annually beginning December 1, 2015. We may redeem some or all of the senior notes at any time at the applicable redemption price, plus accrued interest, if any. The aggregate net proceeds were used to repay our $1 billion 0.90% senior notes that matured in November 2015, and the remainder for general corporate purposes. As of September 30, 2015, we were in compliance with the covenants under the indenture governing the senior notes.
19.  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 September 30,
 
Nine Months Ended September 30,
 
 
(In millions)
2015
 
2014
 
2015
 
2014
 
Income Statement Line
 
 
 
 
Postretirement and postemployment plans
 
 
 
 
 
 
 
 
Amortization of actuarial loss
$
(6
)
 
$
(7
)
 
$
(20
)
 
$
(23
)
 
General and administrative
Net settlement loss
(18
)
 
(22
)
 
(99
)
 
(93
)
 
General and administrative
Net curtailment gain (loss)
(4
)
 
—

 
(1
)
 
—

 
General and administrative
 
(28
)
 
(29
)
 
(120
)
 
(116
)
 
Income (loss) from operations
 
10

 
10

 
44

 
38

 
Benefit for income taxes
Other insignificant, net of tax
—

 
—

 
—

 
(1
)
 
 
Total reclassifications
$
(18
)
 
$
(19
)
 
$
(76
)
 
$
(79
)
 
Income (loss) from continuing operations

20

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


20.  Supplemental Cash Flow Information
 
Nine Months Ended September 30,
(In millions)
2015
 
2014
Net cash used in operating activities:
 
 
 
Interest paid (net of amounts capitalized)
$
(200
)
 
$
(201
)
Income taxes paid to taxing authorities (a)
(174
)
 
(1,514
)
Net cash provided by (used in) financing activities:
 
 
 
Commercial paper, net:
 

 
 

Issuances
$
—

 
$
2,285

Repayments
—

 
(2,420
)
Commercial paper, net
$
—

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

 
 

Asset retirement costs capitalized, net of revisions
$
12

 
$
240

Asset retirement obligations assumed by buyer
23

 
52

Receivable for disposal of assets
—

 
44

(a) 
The first nine months of 2014 included $1,195 million related to discontinued operations.
21.   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.  







21



Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
Executive Overview
Outlook
Operations
Market Conditions
Results of Operations
Critical Accounting Estimates
Cash Flows and Liquidity
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. Our operations are primarily located in North America, Europe and Africa with a focus on our North American unconventional shale plays. Total proved reserves were 2.2 billion boe at December 31, 2014 and total assets were $35 billion at September 30, 2015.
Our significant financial results, operating activities and strategic actions include the following:
•
Increased company-wide net sales volumes from continuing operations by 7% to 445 mboed in the third quarter of 2015 from 417 mboed in the third quarter of 2014
◦
Net sales volumes from our three U.S. resource plays increased 9% to 210 mboed in the third quarter of 2015 from 192 mboed in the third quarter of 2014
•
Maintained focus on cost discipline and efficiencies
◦
Reduced third quarter cash capital expenditures to $628 million, a 28% decrease compared to the previous quarter, reflecting continued capital discipline and benefits from operating efficiencies
◦
Reduced company-wide production expenses per boe in the third quarter of 2015 compared to the same period last year
▪
North America E&P - 27% reduction to $7.43 per boe
▪
International E&P - 47% reduction to $5.53 per boe
▪
Oil Sands Mining - 30% reduction to $26.01 per boe
◦
Achieved 97% average operational availability for our operated assets in the third quarter of 2015
•
Active management of liquidity and capital structure
◦
At the end of the third quarter, we had $5.4 billion of liquidity, including $2.4 billion in cash and short-term investments, $1 billion of which was used to repay our senior notes that matured in November
◦
Cash and short-term investments-adjusted debt-to-capital ratio of 24% at September 30, 2015, as compared with 16% at December 31, 2014
•
Portfolio management activities
◦
We continue to make progress advancing our goal to divest at least $500 million of non-core asset sales
▪
Closed on the sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets in August 2015 for proceeds of approximately $100 million
▪
Signed agreement for sale of our East Africa exploration acreage
•Financial results
◦
Loss from continuing operations per diluted share of $1.11 in the third quarter of 2015 as compared to income from continuing operations of $0.45 per diluted share in the same period last year
◦
Included in the loss for the third quarter are $611 million ($949 million pre-tax) of non-cash charges comprised largely of losses and asset impairments resulting from lower forecasted commodity prices and changes in our conventional exploration strategy (refer to Exploration Update below)
◦
Operating cash flow provided by continuing operations for the first nine months of 2015 was $1.2 billion, compared to $3.5 billion in the same period last year, reflecting the lower commodity price environment

Subsequent to the end of the third quarter, we reduced our quarterly dividend from $0.21 to $0.05 per share to address the uncertainty of a lower for longer commodity price environment, to align with our priority of maintaining a strong balance sheet through the cycle and to provide us with additional capital flexibility to support growth from the U.S. resource plays when commodity prices improve.

22

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. Commodity prices began declining in the second half of 2014 and remain substantially lower through 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, efficiency improvements, cost reductions, capital discipline and portfolio optimization, all while maintaining financial flexibility.
We expect our full-year 2015 capital, investment and exploration budget to be $3.1 billion. We estimate our full-year North America E&P and International E&P production volumes (excluding Libya) to be 380 - 390 net mboed and OSM's synthetic crude oil production to be 40 - 45 net mboed. In addition, based on our current outlook and preliminary plan discussions, we would anticipate a 2016 capital, investment and exploration program of up to $2.2 billion which would give us the flexibility to deliver 2016 annual average production in the U.S. resource plays flat to the 2015 exit rate.
Exploration Update
In September 2015, we announced our intention to scale back our conventional exploration program with an anticipated 2016 program of approximately $100 million, a reduction of 60% as compared to the 2015 budget, subject to approval by our Board of Directors.  Our conventional exploration focus will be redirected to existing commitments in the Gulf of Mexico and Gabon.  As a result, we recorded non-cash impairments related to unproved properties in the Gulf of Mexico and the Harir block in the Kurdistan Region of Iraq in the third quarter.
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 September 30,
 
Nine Months Ended September 30,
Net Sales Volumes
2015
 
2014
 
Increase
(Decrease)
 
2015
 
2014
 
Increase
(Decrease)
North America E&P (mboed)
261
 
250
 
4%
 
273
 
230
 
19%
International E&P (mboed)
119
 
112
 
6%
 
115
 
121
 
(5)%
Oil Sands Mining (mbbld) (a)
65
 
55
 
18%
 
51
 
49
 
4%
Total Continuing Operations (mboed)
445
 
417
 
7%
 
439
 
400
 
10%
(a)    Includes blendstocks

North America E&P--Net Sales Volumes
Net sales volumes in the North America E&P segment increased as a result of continued growth from the combined U.S. resource plays. The following table provides net sales volumes for our significant operational areas within this segment.

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Net Sales Volumes
2015
 
2014
 
Increase
(Decrease)
 
2015
 
2014
 
Increase
(Decrease)
Equivalent Barrels (mboed)
 
 
 
 
 
 
 
 
 
 
 
Eagle Ford
126
 
117
 
8%
 
137
 
105
 
30%
Oklahoma Resource Basins
23
 
19
 
21%
 
24
 
17
 
41%
Bakken
61
 
56
 
9%
 
59
 
50
 
18%
Other North America (a)
51
 
58
 
(12)%
 
53
 
58
 
(9)%
Total North America E&P
261
 
250
 
4%
 
273
 
230
 
19%
(a)  
Includes Gulf of Mexico and other conventional onshore U.S. production.



The following table provides our sales mix for each of our U.S. resource plays.
 
Three Months Ended September 30,
 
2015
 
Eagle Ford
 
Oklahoma Resource Basins
 
Bakken
Crude oil and condensate
59%
 
18%
 
87%
Natural gas liquids
20%
 
28%
 
8%
Natural gas
21%
 
54%
 
5%
 
 
 
 
 
 
 
 
 
 
 
 
The following table presents a summary of our operated drilling activity in the U.S. resource plays:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
Gross Operated
 
 
 
 
 
 
 
Eagle Ford:
 
 
 
 
 
 
 
Wells drilled to total depth
51
 
93
 
198
 
264
Wells brought to sales
57
 
87
 
200
 
212
Oklahoma Resource Basins:
 
 
 
 
 
 
 
Wells drilled to total depth
4
 
4
 
17
 
15
Wells brought to sales
8
 
6
 
16
 
14
Bakken:
 
 
 
 
 
 
 
Wells drilled to total depth
5
 
25
 
30
 
60
Wells brought to sales
5
 
18
 
51
 
52
•
Eagle Ford – Of the 57 gross wells brought to sales during this quarter, 11 were in the Austin Chalk, 6 were in the Upper Eagle Ford, and 40 in the Lower Eagle Ford. Our average time to drill an Eagle Ford well in the third quarter 2015, spud-to-total depth, decreased to 10 days.
•
Oklahoma Resource Basins – During the third quarter, we spud our first Springer well and brought online 8 operated wells (6 in SCOOP and 2 in STACK), with one of the SCOOP wells being an extended-reach lateral. In addition to the 8 wells mentioned above, we completed an additional Smith infill pilot well in the SCOOP which was brought to sales on October 1. These wells are all in the very early stages of production. We continue to leverage the benefit of participation in outside-operated wells and plan to participate in approximately 55-70 gross outside-operated wells in 2015 in the SCOOP Woodford, SCOOP Springer and STACK areas, with 17 outside-operated wells brought to sales during the quarter.
•
Bakken – The 5 gross wells brought to sales this quarter were in the East Myrmidon area. Despite the lower number of wells to sales this quarter, sales volumes were driven by continued strong performance from the Doll pad wells (West Myrmidon) which came online in late June as well as sustained improvement in production uptime. We expect reduced completions activity during the fourth quarter.
•
Gulf of Mexico – Development work continues in the Gunflint field located on Mississippi Canyon Blocks 948, 949, 992 (N/2) and 993 (N/2). We expect the two-well subsea tieback to be complete by the end of 2015 with first oil in mid-2016. We hold an 18% non-operated working interest in the Gunflint field.
North America E&P--Exploration
•
Gulf of Mexico – The third appraisal well on the Shenandoah prospect was spud in May 2015 and reached total depth in October, finding more than 620 feet of net oil pay. The operator completed logging operations and will obtain a whole core across the reservoir interval. The well is located in Walker Ridge Block 51, in which we hold a 10% non-operated working interest. The Solomon exploration prospect located on Walker Ridge Block 225 was spud during the second quarter of 2015 and is expected to reach total depth in the fourth quarter. We hold a 58% operated working interest in this prospect.

24

International E&P--Net Sales Volumes
The following table provides net sales volumes for our significant operational areas within this segment.
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
Increase
(Decrease)
 
2015
 
2014
 
Increase
(Decrease)
Net Sales Volumes
 
 
 
 
 
 
 
 
 
 
 
Equivalent Barrels (mboed)
 
 
 
 
 
 
 
 
 
 
 
Equatorial Guinea
101
 
97
 
4%
 
96
 
104
 
(8)%
United Kingdom(a)
18
 
9
 
100%
 
19
 
15
 
27%
Libya
—
 
6
 
(100)%
 
—
 
2
 
(100)%
Total International E&P (mboed)
119
 
112
 
6%
 
115
 
121
 
(5)%
Net Sales Volumes of Equity Method Investees
 
 
 
 

 
 
 
 
 
 
LNG (mtd)
5,700
 
6,265
 
(9)%
 
5,653
 
6,488
 
(13)%
Methanol (mtd)
1,125
 
1,103
 
2%
 
895
 
1,078
 
(17)%
(a) 
Includes natural gas acquired for injection and subsequent resale of 8 mmcfd and 3 mmcfd for the third quarters of 2015 and 2014, and 8 mmcfd and 5 mmcfd for the first nine months of 2015 and 2014.
•
Equatorial Guinea – Third quarter net sales volumes increased as production from the Alba C21 development well came online with higher than expected yields, combined with a successful wire-line intervention program on five existing Alba wells. The ongoing Alba field compression project, designed to maintain the production plateau two additional years and extend field life up to eight years, achieved mechanical completion at the fabrication yard in the Netherlands during the third quarter and is on schedule to be operational in mid-2016.
•
United Kingdom – Net sales volumes benefited from improved production as two subsea development wells at West Brae began producing during 2015. Overall, operating availability was higher for all U.K. assets in 2015 as compared to comparative 2014 periods which included planned and unplanned maintenance activities. During the third quarter of 2015, planned maintenance activities were completed at the East Brae field and continue at the non-operated Foinaven field. The activity at Foinaven will impact production volumes during the fourth quarter of 2015.
•
Libya – We had no sales during the first nine months of 2015 as a result of continued civil unrest, as compared to one lifting in the third quarter of 2014. In December 2014, Libya’s National Oil Corporation reinstated force majeure at the Es Sider oil terminal. Considerable uncertainty remains around the timing of future production and sales levels.
Oil Sands Mining
 Our net synthetic crude oil sales volumes were 65 mbbld and 51 mbbld in the third quarter and first nine months of 2015 compared to 55 mbbld and 49 mbbld in the same periods of 2014. Net sales volumes increased in the third quarter of 2015 primarily due to improved mine reliability and no major maintenance activities. Planned maintenance at both mines in the fourth quarter of 2015 is expected to impact production. We hold a 20% non-operated working interest in the Athabasca Oil Sands Project. 

 

25


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 third quarter and first nine months of 2015 as compared to the same periods in 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 third quarter and first nine months of 2015 and 2014.
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
Decrease
 
2015
 
2014
 
Decrease
Average Price Realizations (a)
 
 
 
 
 
 
 
 
 
 
 
Crude Oil and Condensate (per bbl) (b)
$41.37
 
$89.65
 
(54)%
 
$45.27
 
$92.59
 
(51)%
Natural Gas Liquids (per bbl)
11.88
 
33.93
 
(65)%
 
13.67
 
36.96
 
(63)%
Total Liquid Hydrocarbons (per bbl)
35.75
 
80.89
 
(56)%
 
39.55
 
83.89
 
(53)%
Natural Gas (per mcf)
2.75
 
4.21
 
(35)%
 
2.84
 
4.81
 
(41)%
Benchmarks
 
 
 
 
 
 
 
 
 
 
 
WTI crude oil (per bbl)
$46.50
 
$97.25
 
(52)%
 
$51.01
 
$99.62
 
(49)%
LLS crude oil (per bbl)
50.22
 
101.03
 
(50)%
 
55.33
 
103.63
 
(47)%
Mont Belvieu NGLs (per bbl) (c)
15.86
 
32.69
 
(51)%
 
17.28
 
35.15
 
(51)%
Henry Hub natural gas (per mmbtu)
2.77
 
4.06
 
(32)%
 
2.80
 
4.55
 
(38)%
(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 $1.87 per bbl and $0.69 per bbl for the third quarter and first nine months of 2015. There were no crude oil derivative instruments in 2014.
(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 third quarter and first nine months of 2015 and 2014.
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
Increase
(Decrease)
 
2015
 
2014
 
Increase
(Decrease)
Average Price Realizations
 
 
 
 
 
 
 
 
 
 
 
Crude Oil and Condensate (per bbl)
$46.18
 
$89.07
 
(48)%
 
$50.51
 
$95.71
 
(47)%
Natural Gas Liquids (per bbl)
2.69
 
1.00
 
169%
 
3.08
 
2.83
 
9%
Liquid Hydrocarbons (per bbl)
35.88
 
66.80
 
(46)%
 
39.21
 
72.88
 
(46)%
Natural Gas (per mcf)
0.59
 
0.56
 
5%
 
0.71
 
0.73
 
(3)%
Benchmark
 
 
 
 

 
 
 
 
 

Brent (Europe) crude oil (per bbl) (a)
$50.23
 
$101.82
 
(51%)
 
$55.28
 
$106.56
 
(48%)
(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.

26


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 third quarter and first nine months of 2015 and 2014.
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
Decrease
 
2015
 
2014
 
Decrease
Average Price Realizations
 
 
 
 
 
 
 
 
 
 
 
Synthetic Crude Oil (per bbl)
$39.49
 
$88.22
 
(55%)
 
$42.26
 
$90.11
 
(53%)
Benchmarks
 
 
 
 
 
 
 
 
 
 
 
WTI crude oil (per bbl)
$46.50
 
$97.25
 
(52%)
 
$51.01
 
$99.62
 
(49%)
WCS crude oil (per bbl)(a) 
33.16
 
76.99
 
(57%)
 
37.80
 
78.50
 
(52%)
(a) 
Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.

27


Results of Operations
Three Months Ended September 30, 2015 vs. Three Months Ended September 30, 2014
Sales and other operating revenues, including related party are presented by segment in the table below:
 
Three Months Ended September 30,
(In millions)
2015
 
2014
Sales and other operating revenues, including related party
 
 
 
North America E&P
$
796

 
$
1,586

International E&P
182

 
273

Oil Sands Mining
242

 
457

Segment sales and other operating revenues, including related party
$
1,220

 
$
2,316

Unrealized gain on crude oil derivative instruments
80

 
—

Sales and other operating revenues, including related party
$
1,300

 
$
2,316

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)
 
September 30, 2014
 
Price Realizations
 
Net Sales Volumes
 
September 30, 2015
North America E&P Price-Volume Analysis
Liquid hydrocarbons
 
$
1,464

 
$
(850
)
 
$
60

 
$
674

Natural gas
 
123

 
(45
)
 
7

 
85

Realized gain on crude oil
 
 
 
 
 
 
 
 
    derivative instruments
 
—

 
28

 


 
28

Other sales
 
(1
)
 


 


 
9

Total
 
$
1,586

 
 
 
 
 
$
796

International E&P Price-Volume Analysis
Liquid hydrocarbons
 
$
240

 
$
(130
)
 
$
42

 
$
152

Natural gas
 
22

 
2

 
—

 
24

Other sales
 
11

 
 
 
 
 
6

Total
 
$
273

 
 
 
 
 
$
182

Oil Sands Mining Price-Volume Analysis
Synthetic crude oil
 
$
445

 
$
(294
)
 
$
85

 
$
236

Other sales
 
12

 


 


 
6

Total
 
$
457

 
 
 
 
 
$
242

Marketing revenues decreased $470 million in the third quarter of 2015 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 $53 million in the third quarter of 2015 from the comparable 2014 period. The decrease is primarily due to lower price realizations for LPG at our Alba plant, LNG at our LNG facility, and lower methanol prices at our AMPCO methanol facility, all of which are located in E.G. Also impacting the quarter was a partial impairment of our investment in an equity method investee.
Production expenses decreased $187 million. North America E&P declined $54 million due to lower operational, maintenance and labor costs. International E&P declined $47 million primarily the result of higher project costs in 2014, such as the non-operated Foinaven subsea power project. Also contributing were lower production costs in Libya during 2015 as the third quarter of 2014 had one lifting. OSM decreased $86 million primarily due to continued cost management, especially staffing and contract labor. Also contributing to the OSM decrease was a more favorable exchange rate on expenses denominated in the Canadian Dollar and lower feedstock purchases given increased reliability.

28


The third quarter of 2015 production expense rate (expense per boe) for North America E&P declined due to overall cost reductions, as previously discussed, and leveraging efficiencies as production volumes increased. 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 as production volume increased, coupled with the increased cost focus discussed above.
The following table provides production expense rates for each segment:
 
Three Months Ended September 30,
($ per boe)
2015
 
2014
Production Expense Rate
 
 
 
North America E&P
$7.43
 
$10.16
International E&P
$5.53
 
$10.48
Oil Sands Mining (a)
$26.01
 
$37.38
(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 $470 million in the third quarter of 2015 from the comparable 2014 period, consistent with the marketing revenues changes discussed above.
 Exploration expenses increased $489 million. We made a strategic decision to reduce the overall level of our conventional exploration program; as a result, we impaired certain of our leases in the Gulf of Mexico and the Harir block in the Kurdistan Region of Iraq. Further contributing to the increase was an impairment of unproved property in Colorado, which we deemed uneconomic given our forecasted natural gas prices. The following table summarizes the components of exploration expenses:
 
Three Months Ended September 30,
(In millions)
2015
 
2014
Exploration Expenses
 
 
 
Unproved property impairments
$
563

 
$
39

Dry well costs
(3
)
 
25

Geological and geophysical
8

 
10

Other
17

 
22

Total exploration expenses
$
585

 
$
96

Depreciation, depletion and amortization (“DD&A”) decreased $20 million primarily as a result of a higher proved reserve base in Eagle Ford, the effects of which more than offset additional DD&A resulting from production volume increases in the International E&P and OSM segments. 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 field-level changes in sales volumes, proved reserves and capitalized costs, 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. The International E&P rate increased primarily due to higher sales volumes from the Brae infill drilling program.
 
Three Months Ended September 30,
($ per boe)
2015
 
2014
DD&A Rate
 
 
 
North America E&P

$22.84

 

$26.54

International E&P

$7.32

 

$5.30

Oil Sands Mining

$12.62

 

$12.75

Impairments are discussed in Note 14 to the consolidated financial statements.

29


Taxes other than income include production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. With the decrease in North America E&P revenues due to lower price realizations, taxes other than income decreased $69 million in the third quarter of 2015. This decrease was partially offset by an increase in sales volumes in North America E&P. The following table summarizes the components of taxes other than income:
 
Three Months Ended September 30,
(In millions)
2015
 
2014
Production and severance
$
28

 
$
69

Ad valorem
2

 
20

Other
16

 
26

Total
$
46

 
$
115

General and administrative expenses decreased $35 million primarily due to cost savings realized from the workforce reductions that occurred in the first quarter of 2015. Pension settlement charges in the three months of 2015 totaled $18 million compared to $22 million in the prior year. In addition, we incurred severance related expenses in the first three months of 2015 associated with workforce reductions of $4 million.
Provision (benefit) for income taxes reflects an effective tax rate of 35% in the third quarter of 2015, as compared to 33% in the third quarter of 2014. See Note 9 to the consolidated financial statements for discussion of the effective tax rate.
Discontinued operations presented in 2014 are net of tax. See Note 6 to the consolidated financial statements for financial information about discontinued operations.
Segment Income (Loss)
Segment income (loss) represents income (loss) 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. Gains or losses on dispositions, certain impairments, unrealized gains or losses on crude oil 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 September 30,
(In millions)
2015
 
2014
North America E&P
$
(61
)
 
$
292

International E&P
29

 
106

Oil Sands Mining
(11
)
 
93

Segment income (loss)
(43
)
 
491

Items not allocated to segments, net of income taxes
(706
)
 
(187
)
Income (loss) from continuing operations
(749
)
 
304

Discontinued operations (a)
—

 
127

Net income (loss)
$
(749
)
 
$
431

(a) 
As a result of the sale of our Angola assets and our Norway business, both are reflected as discontinued operations in 2014.
 North America E&P segment income (loss) decreased $353 million after-tax primarily due to lower price realizations, which was partially offset by the impacts from the increased net sales volumes from the U.S. resource plays and lower production and operating costs.
International E&P segment income decreased $77 million after-tax primarily due to lower liquid hydrocarbon price realizations as well as reduced income from equity investments. These declines were partially offset by increased sales volumes and lower production and exploration expenses.
Oil Sands Mining segment income (loss) decreased $104 million after-tax primarily due to lower price realizations, partially offset by higher volumes and reduced production expenses.

30


Results of Operations
Nine Months Ended September 30, 2015 vs. Nine Months Ended September 30, 2014
Sales and other operating revenues, including related party are presented by segment in the table below:
 
Nine Months Ended September 30,
(In millions)
2015
 
2014
Sales and other operating revenues, including related party
 
 
 
North America E&P
$
2,639

 
$
4,518

International E&P
575

 
1,000

Oil Sands Mining
614

 
1,217

Segment sales and other operating revenues, including related party
$
3,828

 
$
6,735

Unrealized gain on crude oil derivative instruments
59

 
—

Sales and other operating revenues, including related party
$
3,887

 
$
6,735

 
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.
 
 
Nine Months Ended
 
Increase (Decrease) Related to
 
Nine Months Ended
(In millions)
 
September 30, 2014
 
Price Realizations
 
Net Sales Volumes
 
September 30, 2015
North America E&P Price-Volume Analysis
Liquid hydrocarbons
 
$
4,112

 
$
(2,586
)
 
$
781

 
$
2,307

Natural gas
 
398

 
(190
)
 
65

 
273

Realized gain on crude oil
 
 
 
 
 
 
 
 
    derivative instruments
 
—

 
33

 
 
 
33

Other sales
 
8

 
 
 
 
 
26

Total
 
$
4,518

 
 
 
 
 
$
2,639

International E&P Price-Volume Analysis
Liquid hydrocarbons
 
$
873

 
$
(396
)
 
$
(15
)
 
$
462

Natural gas
 
92

 
(2
)
 
(7
)
 
83

Other sales
 
35

 
 
 
 
 
30

Total
 
$
1,000

 
 
 
 
 
$
575

Oil Sands Mining Price-Volume Analysis
Synthetic crude oil
 
$
1,195

 
$
(672
)
 
$
69

 
$
592

Other sales
 
22

 
 
 
 
 
22

Total
 
$
1,217

 
 
 
 
 
$
614

Marketing revenues decreased $1,242 million. 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 $248 million primarily due to lower price realizations for LPG at our Alba Plant, LNG at our LNG facility and lower methanol prices at our AMPCO methanol facility, all of which are located in E.G. Also contributing to the decrease in 2015 were lower sales volumes due to the planned turnaround and maintenance activities at the AMPCO methanol plant, the Alba field and the LNG facility.
Production expenses for the first nine months of 2015 decreased by $397 million. North America E&P declined $101 million due to lower operational, maintenance and labor costs. International E&P declined $115 million due to lower project work, repair, maintenance and turnaround costs as well as slightly lower production volumes. OSM declined $181 million primarily due to continued cost management, especially staffing and contract labor. Also contributing to the OSM decrease are lower feedstock purchases given increased reliability and a more favorable exchange rate on expenses denominated in the Canadian Dollar.

31


The expense rates during the first nine months of 2015 decreased for each of our segments as total production costs declined due to the reasons described in the preceding paragraph. The North America E&P and OSM segments also experienced volume increases, which further contributed to the expense rate decline. The following table provides production expense rates for each segment:
 
Nine Months Ended September 30,
($ per boe)
2015
 
2014
Production Expense Rate
 
 
 
North America E&P

$7.52

 

$10.52

International E&P

$6.13

 

$9.34

Oil Sands Mining (a)

$39.58

 

$44.73

(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 $1,239 million in the first nine months of 2015 from the comparable 2014 period, consistent with the marketing revenues changes discussed above.
 Exploration expenses increased by $472 million as a result of unproved property impairments recognized during the third quarter of 2015. See the preceding three month period discussion for further information on our unproved property impairments. Unproved property impairments in 2014 primarily were a result of Eagle Ford and Bakken leases that either expired or that we decided not to drill or extend. Dry well costs for the first nine months of 2015 include the Sodalita West #1 well in E.G., the Key Largo well in the Gulf of Mexico, and suspended well costs related to Birchwood in-situ that were expensed during the second quarter of 2015. Dry well costs for the first nine months of 2014 primarily consist of our exploration programs in Kurdistan, Ethiopia and Kenya. The following table summarizes the components of exploration expenses:
 
Nine Months Ended September 30,
(In millions)
2015
 
2014
Exploration Expenses
 
 
 
Unproved property impairments
$
612

 
$
140

Dry well costs
96

 
80

Geological and geophysical
23

 
27

Other
55

 
67

Total exploration expenses
$
786

 
$
314

Depreciation, depletion and amortization (“DD&A”) increased $229 million primarily as a result of higher North America E&P net sales volumes from our three U.S. resource plays. 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 field-level changes in sales volumes, proved reserves and capitalized costs, can also cause changes to our DD&A. The following table provides DD&A rates for each segment.
 
Nine Months Ended September 30,
($ per boe)
2015
 
2014
DD&A Rate
 

 
 

North America E&P

$25.09

 

$26.65

International E&P

$6.87

 

$6.09

Oil Sands Mining

$12.60

 

$12.14

Impairments are discussed in Note 14 to the consolidated financial statements.

32


Taxes other than income include production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. With the decrease in North America E&P revenues due to lower price realizations, taxes other than income decreased $128 million in the first nine months of 2015. This decrease was partially offset by an increase in sales volumes in North America E&P. The following table summarizes the components of taxes other than income:
 
Nine Months Ended September 30,
(In millions)
2015
 
2014
Production and severance
$
102

 
$
191

Ad valorem
33

 
58

Other
56

 
70

Total
$
191

 
$
319

General and administrative expenses decreased $22 million primarily due to cost savings realized from the workforce reductions that occurred in the first quarter of 2015. This decrease was partially offset by $47 million of severance related expenses. The first nine months of 2015 include $99 million of pension settlement expense as compared to $93 million for the previous year.
Provision (benefit) for income taxes reflects an effective tax rate of 28% in the first nine months of 2015, as compared to 32% in the comparable 2014 period. The effective rate for 2015 reflects a $135 million non-cash deferred tax expense recorded in the second quarter of 2015 as a result of enacted corporate tax changes in Alberta, Canada. See Note 9 to the consolidated financial statements for discussion of the effective tax rate.
Discontinued operations presented in 2014 are net of tax. See Note 6 to the consolidated financial statements for financial information about discontinued operations.
Segment Income (Loss)
Segment income (loss) represents income (loss) 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. Gains or losses on dispositions, certain impairments, change in tax expense associated with a tax rate change, unrealized gains or losses on crude oil 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):
 
Nine Months Ended September 30,
(In millions)
2015
 
2014
North America E&P
$
(267
)
 
$
836

International E&P
93

 
487

Oil Sands Mining
(107
)
 
212

Segment income (loss)
(281
)
 
1,535

Items not allocated to segments, net of income taxes
(1,130
)
 
(473
)
Income (loss) from continuing operations
(1,411
)
 
1,062

Discontinued operations (a)
—

 
1,058

Net income (loss)
$
(1,411
)
 
$
2,120

(a) 
As a result of the sale of our Angola assets and our Norway business, both are reflected as discontinued operations in 2014.
 North America E&P segment income (loss) decreased $1,103 million after-tax in the first nine months of 2015 primarily due to lower price realizations; these were partially offset by increased net sales volumes from the U.S. resource plays and lower production costs.
International E&P segment income decreased $394 million after-tax primarily due to lower liquid hydrocarbon price realizations and reduced income from equity investments. These declines were partially offset by lower production and exploration expenses.
Oil Sands Mining segment income (loss) decreased $319 million after-tax primarily due to lower price realizations, partially offset by reduced production expenses.

33


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, 2014, except as discussed below.
Fair Value Estimates - Impairment Assessments of Long-Lived Assets and Goodwill
The continued decline of commodity prices resulted in a downward revision of our long-term commodity price assumptions and was a triggering event which required us to reassess long-lived assets related to oil and gas producing properties for impairment as of September 30, 2015. We estimated the fair values using an income approach and concluded that impairments of $337 million were required (See Notes 14 & 15 ). Changes in management's forecast assumptions may cause us to reassess our long-lived assets for impairment, and could result in non-cash impairment charges in the future.
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. After we performed our annual goodwill impairment test in April 2015, a triggering event (downward revision to forecasted commodity price assumptions) required us to reassess our goodwill for impairment as of September 30, 2015. Based on the results of this assessment, we concluded no impairment was required. The fair value of the North America E&P and International E&P reporting units exceeded their respective book values by a significant margin. Changes in management's forecast commodity price assumptions may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.
Income Tax Estimates - 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.
Accounting Standards Not Yet Adopted
See Note 2 to the consolidated financial statements.

34


Cash Flows and Liquidity
 Cash Flows
 The following table presents sources and uses of cash and cash equivalents
 
Nine Months Ended September 30,
(In millions)
2015
2014
Sources of cash and cash equivalents
 

 

Operating activities of continued operations
$
1,213

$
3,476

Operating activities of discontinued operations
—

856

Borrowings
1,996

—

Disposals of assets
105

2,237

Maturities of short-term investments
225

—

Other
97

196

Total sources of cash and cash equivalents
$
3,636

$
6,765

Uses of cash and cash equivalents
 
 
Cash additions to property, plant and equipment
$
(2,948
)
$
(3,639
)
Investing activities of discontinued operations
—

(356
)
Purchases of short-term investments
(925
)
—

Debt issuance costs
(19
)
—

Debt repayments
(34
)
(34
)
Dividends paid
(427
)
(401
)
Purchases of common stock
—

(1,000
)
Commercial paper, net
—

(135
)
Other
(1
)
(48
)
Cash held for sale
—

(655
)
Total uses of cash and cash equivalents
$
(4,354
)
$
(6,268
)
Commodity prices began declining in the second half of 2014 and remain substantially lower through 2015. This lower price trend adversely impacted our cash flows in 2015. Partially offsetting the decline in prices were increased net sales volumes in the North America E&P and OSM segments. While we are unable to predict future commodity price movements, if this lower price environment continues, it would continue to negatively impact our cash flows from operating activities as compared to the previous year.
Borrowings reflect net proceeds received from the issuance of senior notes in June 2015. See Liquidity and Capital Resources below for additional information.
Cash flows from discontinued operations are primarily related to our Norway business, which we disposed of in the fourth quarter of 2014. Disposal of assets in 2015 pertain to the August 2015 sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets. Disposals of assets in 2014 primarily reflect the net proceeds from the sales of our Angola assets. Disposition transactions are discussed in further detail in Note 6 to the consolidated financial statements.
In October, 2015, we announced an adjustment to our quarterly dividend. See Capital Requirements below for additional information.
Certain of our short-term investments matured in September 2015. Purchases of short-term investments in 2015 were made from proceeds received from the senior notes issuance in June 2015. The investments consisted of time deposits with maturity dates ranging from September - October 2015.

35


Additions to property, plant and equipment are our most significant use of cash and cash equivalents. The following table shows capital expenditures by segment and reconciles to additions to property, plant and equipment in continuing operations as presented in the consolidated statements of cash flows:
 
Nine Months Ended September 30,
(In millions)
2015
 
2014
North America E&P
$
2,048

 
$
3,246

International E&P
275

 
386

Oil Sands Mining
26

 
172

Corporate
26

 
29

Total capital expenditures
2,375

 
3,833

(Increase) decrease in capital expenditure accrual
573

 
(194
)
Total use of cash and cash equivalents for property, plant and equipment
$
2,948

 
$
3,639

During the first nine months of 2014, we acquired 29 million common shares at a cost of $1 billion under our share repurchase program. There were no stock repurchases during 2015.
Liquidity and Capital Resources
On June 10, 2015, we issued $2 billion aggregate principal amount of unsecured senior notes which consist of the following series:
•$600 million of 2.70% senior notes due June 1, 2020
•$900 million of 3.85% senior notes due June 1, 2025
•$500 million of 5.20% senior notes due June 1, 2045
Interest on each series of senior notes is payable semi-annually beginning December 1, 2015. We used the aggregate net proceeds to repay our $1 billion 0.90% senior notes on November 2, 2015, and the remainder for general corporate purposes.
In May 2015, we amended our $2.5 billion Credit Facility to increase the facility size by $500 million to a total of $3 billion and extend the maturity date by an additional year such that the Credit Facility now matures in May 2020.  The amendment additionally provides us the ability to request two one-year extensions to the maturity date and an option to increase the commitment amount by up to an additional $500 million, subject to the consent of any increasing lenders.  The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively.  Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unchanged.
Our main sources of liquidity are cash and cash equivalents, short-term investments, internally generated cash flow from operations, the issuance of notes, our $3 billion Credit Facility and sales of non-core assets. Our working capital requirements are supported by these sources and we may also issue commercial paper, which is backed by our revolving credit facility. Furthermore, we actively manage our capital spending program, including the level and timing of activities associated with our drilling programs. Because of the alternatives available to us as discussed above, and access to capital markets through the shelf registration discussed below, we believe that our liquidity is adequate to fund not only our current operations, but also our funding requirements for the foreseeable future, 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.



36


Capital Resources
Credit Arrangements and Borrowings
At September 30, 2015, we had no borrowings against our revolving credit facility and no amounts outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.
At September 30, 2015, we had $8.4 billion in long-term debt outstanding, of which approximately $1.0 billion matured and was repaid in November 2015. We utilized cash on hand and proceeds from the maturities of our short-term investments to fund the debt payment. 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. 
Asset Disposals
We are targeting to generate at least $500 million from select non-core asset sales. During the third quarter of 2015, we closed the sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets for proceeds of approximately $100 million and announced the sale of our Kenya and Ethiopia exploration acreage. See Note 6 to the consolidated financial statements for additional discussion of these dispositions.        
Cash and Short-Term Investments-Adjusted Debt-To-Capital Ratio
 Our cash and short-term investments-adjusted debt-to-capital ratio (total debt-minus-cash and cash equivalents and short-term investments to total debt-plus-equity-minus-cash and cash equivalents and short-term investments) was 24% at September 30, 2015, compared to 16% at December 31, 2014.
 
September 30,
 
December 31,
(In millions)
2015
 
2014
Long-term debt due within one year
$
1,035

 
$
1,068

Long-term debt
7,323

 
5,323

Total debt
$
8,358

 
$
6,391

Cash and cash equivalents
$
1,680

 
$
2,398

Short-term investments
$
700

 
$
—

Equity
$
19,335

 
$
21,020

Calculation:
 

 
 

Total debt
$
8,358

 
$
6,391

Minus cash and cash equivalents
1,680

 
2,398

Minus short-term investments
700

 
—

Total debt minus cash, cash equivalents and short-term investments
$
5,978

 
$
3,993

Total debt
$
8,358

 
$
6,391

Plus equity
19,335

 
21,020

Minus cash and cash equivalents
1,680

 
2,398

Minus short-term investments
700

 
—

Total debt plus equity minus cash, cash equivalents and short-term investments
$
25,313

 
$
25,013

Cash and short-term investments-adjusted debt-to-capital ratio
24
%
 
16
%
Capital Requirements
We expect our revised total capital, investment and exploration spending budget for full-year 2015 to be $3.1 billion which is $200 million less than our previous budget.
On October 28, 2015, our Board of Directors approved a dividend of $0.05 per share for the third quarter of 2015 payable December 10, 2015 to stockholders of record at the close of business on November 18, 2015. This dividend represents a reduction from the previous quarterly dividend of $0.21 per share as we continue to address the uncertainty of a lower for longer commodity price environment, align with our priority of maintaining a strong balance sheet through the cycle, and provide additional capital flexibility to support growth from the U.S. resource plays when commodity prices improve.
As of September 30, 2015, we plan to make contributions of up to $18 million to our funded pension plans during the remainder of 2015.

37


Contractual Cash Obligations
As of September 30, 2015, there are no material changes to our consolidated cash obligations to make future payments under existing contracts, as disclosed in our 2014 Annual Report on Form 10-K, except for our issuance of $2 billion aggregate principal amount of unsecured senior notes, as more fully described in Note 18.
 
 
 
 
 
 
 
 
 
 
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, 2014.
Other 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.  
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, financial and growth strategies, including planned projects, drilling plans, maintenance activities, asset sales, productivity improvements, and drilling and completion efficiencies; our ability to effect those strategies 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 2015 and 2016 capital, investment and exploration programs, including planned allocation and reductions, and the expected benefits thereof; our declared dividend and the expected benefits thereof; our financial position, liquidity and capital resources; production guidance; 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 key operating markets, including international markets;
•
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 2014 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.

38


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 2014 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 15 and 16 to the consolidated financial statements.
Commodity Price Risk During the first nine months of 2015, we entered into crude oil derivatives, indexed to NYMEX WTI, related to a portion of our forecasted North America E&P sales. The table below provides a summary of open positions as of September 30, 2015:
Financial Instrument
Weighted Average Price
Barrels per day
Remaining Term
Three-Way Collars
 
 
 
Ceiling
$70.34
35,000
October- December 2015
Floor
$55.57
 
 
Sold put
$41.29
 
 
 
 
 
 
Ceiling
$60.00
2,000
October 2015- March 2016 (a)
Floor
$50.00
 
 
Sold put
$40.00
 
 
 
 
 
 
Ceiling
$71.84
12,000
January- December 2016
Floor
$60.48
 
 
Sold put
$50.00
 
 
 
 
 
 
Ceiling
$73.13
2,000
January- June 2016 (b)
Floor
$65.00
 
 
Sold put
$50.00
 
 
Call Options 
$72.39
10,000
January- December 2016 (c)
(a) 
Counterparties have the option, exercisable on March 31, 2016, to extend these collars through September of 2016 at the same volume and weighted average price as the underlying three-way collars.
(b) 
Counterparty has the option, exercisable on June 30, 2016, to extend these collars through the remainder of 2016 at the same volume and weighted average price as the underlying three-way collars.
(c) 
Call options settle monthly.
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 prices on our open commodity derivative instruments as of September 30, 2015.
(In millions)
Hypothetical Price Increase of 10%
Hypothetical Price Decrease of 10%
Crude oil commodity derivatives
$
(46
)
$
6


Interest Rate Risk Sensitivity analysis of the incremental effect of a hypothetical 10 percent change in interest rates on financial assets and liabilities as of September 30, 2015, is provided in the following table.
(In millions)
Fair Value
 
Incremental Change in Fair Value
Financial assets (liabilities):
 
 
 
Long term debt, including amounts due within one year
$
(8,302
)
(a)(b) 
$
(295
)
(a) 
Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.
(b) 
Excludes capital leases.
    

39


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 September 30, 2015.  
During the third quarter of 2015, 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.

40


Part II – OTHER INFORMATION
Item 1. Legal Proceedings
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.  
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 2014 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 September 30, 2015, 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
07/01/15 - 07/31/15
3,333

 
25.58

 
—

 
$1,500,285,529
08/01/15 - 08/31/15
46,543

 
18.50

 
—

 
$1,500,285,529
09/01/15 - 09/30/15
5,444

 
15.01

 
—

 
$1,500,285,529
Total
55,320

 
18.59

 
—

 
 
(a) 
55,320 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.
Item 5. Other Information
As we previously disclosed in a Form 8-K filed with the SEC on August 28, 2015, our Board of Directors amended and restated our By-laws, effective September 1, 2015, to modify the existing proxy access provisions of the By-laws to coincide with the stockholder proposal that was approved at our 2015 annual meeting of stockholders.
Pursuant to these amendments, the required ownership percentage needed to use the proxy access provisions was decreased to 3% of Marathon Oil’s outstanding common stock, owned continuously for at least three years. Additionally, the maximum number of stockholder nominees that may be included in the proxy statement pursuant to these provisions was increased to 25% of the number of directors in office as of the last day on which notice requesting proxy access may be delivered by an eligible stockholder.
Item 6.  Exhibits
The information required by this Item 6 is set forth in the Exhibit Index accompanying this Form 10-Q.

41


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.
November 5, 2015
 
MARATHON OIL CORPORATION
 
 
 
 
By:
/s/ Gary E. Wilson
 
 
Gary E. Wilson
 
 
Vice President, Controller and Chief Accounting Officer
 
 
(Duly Authorized Officer)

42


Exhibit Index
 
 
 
Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
Exhibit Number
 
Exhibit Description
Form
 
Exhibit
 
Filing Date
 
2.1++
 
Separation and Distribution Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Oil Company and Marathon Petroleum Corporation
8-K
 
2.1
 
5/26/2011
 
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 September 1, 2015)
8-K
 
3.1
 
8/28/2015
 
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.
 
 
 
 
 
 
++
 
Marathon Oil agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request.