UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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(Mark One)
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[X]
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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For the Quarterly Period Ended June 30, 2016
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OR
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[ ]
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from _____ to _____
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Commission file number 1-5153
Marathon Oil Corporation
(Exact name of registrant as specified in its charter)
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Delaware
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25-0996816
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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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.
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Large accelerated filer
þ
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Accelerated filer
o
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Non-accelerated filer
o
(Do not check if a smaller reporting company)
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Smaller reporting company
o
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes
o
No
þ
There were
847,258,512
shares of Marathon Oil Corporation common stock outstanding as of
July 31, 2016
.
MARATHON OIL CORPORATION
Unless the context otherwise indicates, references to “Marathon Oil,” “we,” “our,” or “us” in this Form 10-Q are references to Marathon Oil Corporation, including its wholly-owned and majority-owned subsidiaries, and its ownership interests in equity method investees (corporate entities, partnerships, limited liability companies and other ventures over which Marathon Oil exerts significant influence by virtue of its ownership interest).
For certain industry specific terms used in this Form 10-Q, please see "Definitions" in our
2015
Annual Report on Form 10-K.
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Table of Contents
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Page
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1
Part I - Financial Information
Item 1. Financial Statements
MARATHON OIL CORPORATION
Consolidated Statements of Income (Unaudited)
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Three Months Ended
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Six Months Ended
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||||||||||||
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June 30,
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June 30,
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||||||||||||
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(In millions, except per share data)
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2016
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2015
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2016
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2015
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||||||||
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Revenues and other income:
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Sales and other operating revenues, including related party
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$
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870
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$
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1,307
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$
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1,584
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$
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2,587
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Marketing revenues
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89
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183
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147
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387
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Income from equity method investments
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37
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26
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51
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62
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Net gain (loss) on disposal of assets
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294
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—
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234
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1
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Other income
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12
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15
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16
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26
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Total revenues and other income
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1,302
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1,531
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2,032
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3,063
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Costs and expenses:
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Production
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350
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450
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678
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894
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Marketing, including purchases from related parties
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88
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182
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146
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387
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Other operating
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95
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81
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204
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188
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Exploration
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189
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111
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213
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201
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Depreciation, depletion and amortization
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561
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751
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1,170
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1,572
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Impairments
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—
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44
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1
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44
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Taxes other than income
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39
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78
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87
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145
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General and administrative
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132
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168
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283
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339
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Total costs and expenses
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1,454
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1,865
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2,782
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3,770
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Income (loss) from operations
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(152
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)
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(334
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)
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(750
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)
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(707
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)
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Net interest and other
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(86
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)
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(58
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)
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(171
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)
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(105
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)
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Income (loss) before income taxes
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(238
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)
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(392
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)
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(921
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)
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(812
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)
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Provision (benefit) for income taxes
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(68
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)
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(6
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)
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(344
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)
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(150
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)
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Net income (loss)
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$
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(170
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)
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$
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(386
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)
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$
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(577
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)
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$
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(662
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)
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Net income (loss) per share:
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Basic
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$
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(0.20
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)
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$
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(0.57
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)
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$
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(0.73
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)
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$
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(0.98
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)
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Diluted
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$
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(0.20
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)
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$
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(0.57
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)
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$
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(0.73
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)
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$
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(0.98
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)
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Dividends per share
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$
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0.05
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$
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0.21
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$
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0.10
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$
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0.42
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Weighted average common shares outstanding:
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Basic
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848
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677
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790
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676
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Diluted
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848
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677
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790
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676
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The accompanying notes are an integral part of these consolidated financial statements
.
2
MARATHON OIL CORPORATION
Consolidated Statements of Comprehensive Income (Unaudited)
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Three Months Ended
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Six Months Ended
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June 30,
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June 30,
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||||||||||||
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(In millions)
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2016
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2015
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2016
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2015
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Net income (loss)
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$
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(170
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)
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$
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(386
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)
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$
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(577
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)
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$
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(662
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)
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Other comprehensive income (loss)
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Postretirement and postemployment plans
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Change in actuarial loss and other
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19
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86
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(5
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)
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162
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Income tax provision (benefit)
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(7
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)
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(30
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)
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2
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(57
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)
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Postretirement and postemployment plans, net of tax
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12
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56
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(3
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)
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105
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Other, net of tax
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(2
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)
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—
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(2
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)
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—
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Other comprehensive income (loss)
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10
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56
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(5
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)
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105
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Comprehensive income (loss)
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$
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(160
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)
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$
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(330
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)
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$
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(582
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)
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$
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(557
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)
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The accompanying notes are an integral part of these consolidated financial statements
.
3
MARATHON OIL CORPORATION
Consolidated Balance Sheets (Unaudited)
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June 30,
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December 31,
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||||
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(In millions, except per share data)
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2016
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2015
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Assets
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Current assets:
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Cash and cash equivalents
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$
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2,584
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$
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1,221
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Receivables, less reserve of $4 and $4
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822
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912
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Inventories
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272
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313
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Other current assets
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76
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144
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Total current assets
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3,754
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2,590
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Equity method investments
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944
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1,003
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Property, plant and equipment, less accumulated depreciation,
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depletion and amortization of $21,659 and $23,260
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25,657
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27,061
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Goodwill
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115
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115
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Other noncurrent assets
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2,057
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1,542
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Total assets
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$
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32,527
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$
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32,311
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Liabilities
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Current liabilities:
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Accounts payable
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$
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953
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$
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1,313
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Payroll and benefits payable
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114
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133
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Accrued taxes
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85
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132
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Other current liabilities
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229
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150
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Long-term debt due within one year
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1
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1
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Total current liabilities
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1,382
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1,729
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Long-term debt
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7,280
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7,276
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Deferred tax liabilities
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2,392
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2,441
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Defined benefit postretirement plan obligations
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409
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403
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Asset retirement obligations
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1,597
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1,601
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Deferred credits and other liabilities
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314
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308
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Total liabilities
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13,374
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13,758
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Commitments and contingencies
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Stockholders’ Equity
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Preferred stock – no shares issued or outstanding (no par value,
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26 million shares authorized)
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—
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—
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Common stock:
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Issued – 937 million shares and 770 million shares (par value $1 per share,
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||||
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1.1 billion shares authorized)
|
937
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770
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Securities exchangeable into common stock – no shares issued or
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outstanding (no par value, 29 million shares authorized)
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—
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—
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Held in treasury, at cost – 89 million and 93 million shares
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(3,397
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)
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(3,554
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)
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Additional paid-in capital
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7,433
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|
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6,498
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Retained earnings
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14,320
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14,974
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Accumulated other comprehensive loss
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(140
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)
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(135
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)
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Total stockholders' equity
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19,153
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|
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18,553
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Total liabilities and stockholders' equity
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$
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32,527
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|
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$
|
32,311
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The accompanying notes are an integral part of these consolidated financial statements
.
4
MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows (Unaudited)
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Six Months Ended
|
||||||
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June 30,
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||||||
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(In millions)
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2016
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2015
|
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Increase (decrease) in cash and cash equivalents
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|
||||
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Operating activities:
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|
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Net income (loss)
|
$
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(577
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)
|
|
$
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(662
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)
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Adjustments to reconcile net income (loss) to net cash provided by operating activities:
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Deferred income taxes
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(392
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)
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(185
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)
|
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Depreciation, depletion and amortization
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1,170
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|
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1,572
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Impairments
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1
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44
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|
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Net (gain) loss on derivative instruments
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88
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17
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|
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Net cash received (paid) in settlement of derivative instruments
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46
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4
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Pension and other postretirement benefits, net
|
14
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|
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14
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|
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Exploratory dry well costs and unproved property impairments
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166
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|
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148
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|
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Net (gain) loss on disposal of assets
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(234
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)
|
|
(1
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)
|
||
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Equity method investments, net
|
22
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|
|
37
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|
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Changes in:
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Current receivables
|
88
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|
|
534
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|
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Inventories
|
30
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|
|
21
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|
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Current accounts payable and accrued liabilities
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(211
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)
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(770
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)
|
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All other operating, net
|
41
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|
|
(56
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)
|
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Net cash provided by operating activities
|
252
|
|
|
717
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|
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Investing activities:
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|
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Additions to property, plant and equipment
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(753
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)
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|
(2,320
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)
|
||
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Disposal of assets
|
758
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|
|
2
|
|
||
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Investments - return of capital
|
37
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|
|
31
|
|
||
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Purchases of short-term investments
|
—
|
|
|
(925
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)
|
||
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Deposit for acquisition
|
(89
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)
|
|
—
|
|
||
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All other investing, net
|
2
|
|
|
(1
|
)
|
||
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Net cash used in investing activities
|
(45
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)
|
|
(3,213
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)
|
||
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Financing activities:
|
|
|
|
|
|
||
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Borrowings
|
—
|
|
|
1,996
|
|
||
|
Debt issuance costs
|
—
|
|
|
(19
|
)
|
||
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Debt repayments
|
—
|
|
|
(34
|
)
|
||
|
Common stock issuance
|
1,236
|
|
|
—
|
|
||
|
Dividends paid
|
(77
|
)
|
|
(285
|
)
|
||
|
All other financing, net
|
—
|
|
|
11
|
|
||
|
Net cash provided by (used in) financing activities
|
1,159
|
|
|
1,669
|
|
||
|
Effect of exchange rate on cash and cash equivalents
|
(3
|
)
|
|
1
|
|
||
|
Net increase (decrease) in cash and cash equivalents
|
1,363
|
|
|
(826
|
)
|
||
|
Cash and cash equivalents at beginning of period
|
1,221
|
|
|
2,398
|
|
||
|
Cash and cash equivalents at end of period
|
$
|
2,584
|
|
|
$
|
1,572
|
|
The accompanying notes are an integral part of these consolidated financial statements
.
5
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.
A reclassification between operating cash flow categories was made to the prior year's financial information to present it on a basis comparable with the current year's presentation with no impact on net cash provided by operating activities.
These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our
2015
Annual Report on Form 10-K. The results of operations for the
second quarter and first six months of
2016
are not necessarily indicative of the results to be expected for the full year.
2
. Accounting Standards
Not Yet Adopted
In June 2016, the FASB issued a new accounting standards update that changes the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. The standard requires the use of a forward-looking "expected loss" model as opposed to the current "incurred loss" model. This standard is effective for us in the first quarter of 2020 and will be adopted on a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period. Early adoption is permitted starting January 2019. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.
In March 2016, the FASB issued a new accounting standards update that changes several aspects of accounting for share-based payment transactions, including a requirement to recognize all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This standard is effective for us in the first quarter of 2017 and varying transition methods (modified retrospective, retrospective or prospective) should be applied to different provisions of the standard. Early adoption is permitted. We continue to evaluate the provisions of this accounting standards update but do not believe it will have a material effect on our consolidated results of operations, financial position or cash flows.
In February 2016, the FASB issued a new lease accounting standard, which requires lessees to recognize most leases, including operating leases, on the balance sheet as a right of use asset and lease liability. Short-term leases can continue being accounted for off balance sheet based on a policy election. This standard is effective for us in the first quarter of 2019 and should be applied using a modified retrospective approach at the beginning of the earliest period presented in the financial statements. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it will have on our consolidated results of operations, financial position or cash flows.
In January 2016, the FASB issued an accounting standards update that addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. This standard is effective for us in the first quarter of 2018. Early adoption is allowed for certain provisions. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In July 2015, the FASB issued an update that requires an entity to measure inventory at the lower of cost and net realizable value. This excludes inventory measured using LIFO or the retail inventory method. This standard is effective for us in the first quarter of 2017 and will be applied prospectively. Early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In August 2014, the FASB issued an update that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards. This standard is effective for us for the annual period ending after December 15, 2016 and for annual periods and interim periods thereafter. Early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
6
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
In May 2014, the FASB issued an update that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. Among other things, the standard requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for us in the first quarter of 2018 and should be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. While early adoption is permitted, we plan to adopt in the first quarter of 2018. We continue to evaluate certain provisions of this accounting standards update and are assessing the impact it will have on our consolidated results of operations, financial position or cash flows.
Recently Adopted
In May 2015, the FASB issued an update that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The amendment also removes certain disclosure requirements regarding all investments that are eligible to be measured using the net asset value per share practical expedient and only requires certain disclosures on those investments for which an entity elects to use the net asset value per share expedient. This standard is effective for us in the first quarter of 2016 and was applied on a retrospective basis. This standard only modifies disclosure requirements; as such, there was no impact on our consolidated results of operations, financial position or cash flows.
In February 2015, the FASB issued an amendment to the guidance for determining whether an entity is a variable interest entity ("VIE"). The standard does not add or remove any of the five characteristics that determine whether an entity is a VIE. However, it does change the manner in which a reporting entity assesses one of the characteristics. In particular, when decision-making over the entity’s most significant activities has been outsourced, the standard changes how a reporting entity assesses if the equity holders at risk lack decision making rights. This standard is effective for us in the first quarter of 2016. The adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.
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
June 30, 2016
and
December 31, 2015
. This contract qualifies as a variable interest contractual arrangement, and the Corridor Pipeline qualifies as a VIE. We hold a variable interest but are not the primary beneficiary because our shipments are only
20%
of the total; therefore, the Corridor Pipeline is not consolidated by us. Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was
$468 million
as of
June 30, 2016
. The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term.
7
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
|
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
14 million
stock options for the three and six month periods ended
June 30, 2016
and
13 million
stock options for the three and six month periods ended
June 30, 2015
that were antidilutive.
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
(In millions, except per share data)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
|
Net income (loss)
|
$
|
(170
|
)
|
|
$
|
(386
|
)
|
|
$
|
(577
|
)
|
|
$
|
(662
|
)
|
|
|
|
|
|
|
|
|
|
||||||||
|
Weighted average common shares outstanding
|
848
|
|
|
677
|
|
|
790
|
|
|
676
|
|
||||
|
Weighted average common shares, diluted
|
848
|
|
|
677
|
|
|
790
|
|
|
676
|
|
||||
|
Net income (loss) per share:
|
|
|
|
|
|
|
|
||||||||
|
Basic
|
$
|
(0.20
|
)
|
|
$
|
(0.57
|
)
|
|
$
|
(0.73
|
)
|
|
$
|
(0.98
|
)
|
|
Diluted
|
$
|
(0.20
|
)
|
|
$
|
(0.57
|
)
|
|
$
|
(0.73
|
)
|
|
$
|
(0.98
|
)
|
5
. Acquisitions
In June 2016, we executed a purchase agreement to acquire PayRock Energy Holdings, LLC ("PayRock"), a portfolio company of EnCap Investments, which closed on
August 1, 2016
for
$888 million
, subject to closing adjustments. PayRock has approximately
61,000
net surface acres and current production of approximately
9,000
net barrels of oil equivalent in the oil window of the Anadarko Basin STACK play in Oklahoma. In the second quarter of 2016 an
$89 million
deposit was paid into escrow related to the acquisition. The purchase price was paid with cash on hand. We accounted for this transaction as an asset acquisition, with the majority of the purchase price allocated to property, plant and equipment.
|
6
.
|
Dispositions
|
2016 - North America E&P Segment
During the quarter, we announced the sale of our Wyoming upstream and midstream assets for proceeds of $
870 million
, before closing adjustments, of which approximately $
690 million
was received in the second quarter. A pre-tax gain of
$266
million was recognized in the second quarter 2016. The remaining asset sales are subject to the receipt of certain tribal consents and are expected to close before year end. These assets are classified as held for sale in the consolidated balance sheet as of June 30, 2016 with total assets of $
104 million
and total liabilities of $
4 million
. The proceeds for the remaining asset sales were deposited into an escrow account by the buyer.
In March and April 2016, we entered into separate agreements to sell our
10%
working interest in the outside-operated Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Colorado and certain undeveloped acreage in West Texas for a combined total of approximately $
80
million in proceeds, before closing adjustments. We closed on certain of the asset sales and recognized a net pre-tax net loss on sale of $
48 million
for the six months ended June 30, 2016. The remaining asset sales are expected to close by year-end.
2015 - North America E&P Segment
In the third quarter of 2015, we closed on 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 as a result of the anticipated sale (see Note
13
).
|
|
|
8
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
7
. Segment Information
We have three reportable operating segments. Each of these segments is organized and managed based upon both geographic location and the nature of the products and services it offers.
|
•
|
N.A. E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in North America;
|
|
•
|
Int'l E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.; and
|
|
•
|
Oil Sands Mining (“OSM”) – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
|
Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”). Segment income represents income which excludes certain items not allocated to segments, net of income taxes, attributable to the operating segments. A portion of our corporate and operations support general and administrative costs are not allocated to the operating segments. These unallocated costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Additionally, items which affect comparability such as: gains or losses on dispositions, certain impairments, change in tax expense associated with a tax rate change, unrealized gains or losses on commodity derivative instruments, pension settlement losses or other items (as determined by the CODM) are not allocated to operating segments.
|
|
Three Months Ended June 30, 2016
|
||||||||||||||||||
|
|
|
|
Not Allocated
|
|
|
||||||||||||||
|
(In millions)
|
N.A. E&P
|
|
Int'l E&P
|
|
OSM
|
|
to Segments
|
|
Total
|
||||||||||
|
Sales and other operating revenues
|
$
|
617
|
|
|
$
|
159
|
|
|
$
|
185
|
|
|
$
|
(91
|
)
|
(c)
|
$
|
870
|
|
|
Marketing revenues
|
53
|
|
|
23
|
|
|
13
|
|
|
—
|
|
|
89
|
|
|||||
|
Total revenues
|
670
|
|
|
182
|
|
|
198
|
|
|
(91
|
)
|
|
959
|
|
|||||
|
Income from equity method investments
|
—
|
|
|
37
|
|
|
—
|
|
|
—
|
|
|
37
|
|
|||||
|
Net gain on disposal of assets and other income
|
2
|
|
|
7
|
|
|
1
|
|
|
296
|
|
(d)
|
306
|
|
|||||
|
Less:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Production expenses
|
129
|
|
|
56
|
|
|
165
|
|
|
—
|
|
|
350
|
|
|||||
|
Marketing costs
|
52
|
|
|
23
|
|
|
13
|
|
|
—
|
|
|
88
|
|
|||||
|
Exploration expenses
|
37
|
|
|
4
|
|
|
7
|
|
|
141
|
|
(e)
|
189
|
|
|||||
|
Depreciation, depletion and amortization
|
433
|
|
|
68
|
|
|
49
|
|
|
11
|
|
|
561
|
|
|||||
|
Other expenses
(a)
|
97
|
|
|
22
|
|
|
9
|
|
|
99
|
|
(f)
|
227
|
|
|||||
|
Taxes other than income
|
35
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
39
|
|
|||||
|
Net interest and other
|
—
|
|
|
—
|
|
|
—
|
|
|
86
|
|
|
86
|
|
|||||
|
Income tax benefit
|
(41
|
)
|
|
(2
|
)
|
|
(10
|
)
|
|
(15
|
)
|
|
(68
|
)
|
|||||
|
Segment income (loss) / Net income (loss)
|
$
|
(70
|
)
|
|
$
|
55
|
|
|
$
|
(38
|
)
|
|
$
|
(117
|
)
|
|
$
|
(170
|
)
|
|
Capital expenditures
(b)
|
$
|
153
|
|
|
$
|
12
|
|
|
$
|
7
|
|
|
$
|
5
|
|
|
$
|
177
|
|
|
(a)
|
Includes other operating expenses and general and administrative expenses.
|
|
(b)
|
Includes accruals.
|
|
(c)
|
Unrealized loss on commodity derivative instruments.
|
|
(d)
|
Primarily related to partial sale of Wyoming upstream and midstream assets. (See note
6
.)
|
|
(e)
|
Impairments associated with decision to not drill remaining Gulf of Mexico undeveloped leases.
|
|
(f)
|
Includes pension settlement loss of
$31 million
(See note
8
).
|
9
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
|
|
Three Months Ended June 30, 2015
|
||||||||||||||||||
|
|
|
|
Not Allocated
|
|
|
||||||||||||||
|
(In millions)
|
N.A. E&P
|
|
Int'l E&P
|
|
OSM
|
|
to Segments
|
|
Total
|
||||||||||
|
Sales and other operating revenues
|
$
|
993
|
|
|
$
|
211
|
|
|
$
|
147
|
|
|
$
|
(44
|
)
|
(c)
|
$
|
1,307
|
|
|
Marketing revenues
|
110
|
|
|
30
|
|
|
43
|
|
|
—
|
|
|
183
|
|
|||||
|
Total revenues
|
1,103
|
|
|
241
|
|
|
190
|
|
|
(44
|
)
|
|
1,490
|
|
|||||
|
Income from equity method investments
|
—
|
|
|
26
|
|
|
—
|
|
|
—
|
|
|
26
|
|
|||||
|
Net gain on disposal of assets and other income
|
11
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
15
|
|
|||||
|
Less:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Production expenses
|
179
|
|
|
64
|
|
|
207
|
|
|
—
|
|
|
450
|
|
|||||
|
Marketing costs
|
112
|
|
|
29
|
|
|
41
|
|
|
—
|
|
|
182
|
|
|||||
|
Exploration expenses
|
91
|
|
|
20
|
|
|
—
|
|
|
—
|
|
|
111
|
|
|||||
|
Depreciation, depletion and amortization
|
634
|
|
|
71
|
|
|
35
|
|
|
11
|
|
|
751
|
|
|||||
|
Impairments
|
—
|
|
|
—
|
|
|
—
|
|
|
44
|
|
(d)
|
44
|
|
|||||
|
Other expenses
(a)
|
99
|
|
|
19
|
|
|
9
|
|
|
122
|
|
(e)
|
249
|
|
|||||
|
Taxes other than income
|
67
|
|
|
—
|
|
|
5
|
|
|
6
|
|
|
78
|
|
|||||
|
Net interest and other
|
—
|
|
|
—
|
|
|
—
|
|
|
58
|
|
|
58
|
|
|||||
|
Income tax provision (benefit)
|
(23
|
)
|
|
27
|
|
|
(30
|
)
|
|
20
|
|
(f)
|
(6
|
)
|
|||||
|
Segment income (loss) / Net income (loss)
|
$
|
(45
|
)
|
|
$
|
41
|
|
|
$
|
(77
|
)
|
|
$
|
(305
|
)
|
|
$
|
(386
|
)
|
|
Capital expenditures
(b)
|
$
|
551
|
|
|
$
|
99
|
|
|
$
|
16
|
|
|
$
|
12
|
|
|
$
|
678
|
|
|
(a)
|
Includes other operating expenses and general and administrative expenses.
|
|
(b)
|
Includes accruals.
|
|
(c)
|
Unrealized loss on commodity derivative instruments.
|
|
(d)
|
Proved property impairment (See Note
13
).
|
|
(e)
|
Includes pension settlement loss of
$64 million
(see Note
8
).
|
|
(f)
|
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)
|
|
Six Months Ended June 30, 2016
|
||||||||||||||||||
|
|
|
|
Not Allocated
|
|
|
||||||||||||||
|
(In millions)
|
N.A. E&P
|
|
Int'l E&P
|
|
OSM
|
|
to Segments
|
|
Total
|
||||||||||
|
Sales and other operating revenues
|
$
|
1,110
|
|
|
$
|
255
|
|
|
$
|
333
|
|
|
$
|
(114
|
)
|
(c)
|
$
|
1,584
|
|
|
Marketing revenues
|
84
|
|
|
38
|
|
|
25
|
|
|
—
|
|
|
147
|
|
|||||
|
Total revenues
|
1,194
|
|
|
293
|
|
|
358
|
|
|
(114
|
)
|
|
1,731
|
|
|||||
|
Income from equity method investments
|
—
|
|
|
51
|
|
|
—
|
|
|
—
|
|
|
51
|
|
|||||
|
Net gain on disposal of assets and other income
|
3
|
|
|
13
|
|
|
1
|
|
|
233
|
|
(d)
|
250
|
|
|||||
|
Less:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Production expenses
|
263
|
|
|
109
|
|
|
306
|
|
|
—
|
|
|
678
|
|
|||||
|
Marketing costs
|
84
|
|
|
37
|
|
|
25
|
|
|
—
|
|
|
146
|
|
|||||
|
Exploration expenses
|
55
|
|
|
10
|
|
|
7
|
|
|
141
|
|
(e)
|
213
|
|
|||||
|
Depreciation, depletion and amortization
|
920
|
|
|
118
|
|
|
109
|
|
|
23
|
|
|
1,170
|
|
|||||
|
Impairments
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
|
Other expenses
(a)
|
215
|
|
|
38
|
|
|
16
|
|
|
218
|
|
(f)
|
487
|
|
|||||
|
Taxes other than income
|
77
|
|
|
—
|
|
|
9
|
|
|
1
|
|
|
87
|
|
|||||
|
Net interest and other
|
—
|
|
|
—
|
|
|
—
|
|
|
171
|
|
|
171
|
|
|||||
|
Income tax benefit
|
(153
|
)
|
|
(14
|
)
|
|
(27
|
)
|
|
(150
|
)
|
|
(344
|
)
|
|||||
|
Segment income (loss) / Net income (loss)
|
$
|
(265
|
)
|
|
$
|
59
|
|
|
$
|
(86
|
)
|
|
$
|
(285
|
)
|
|
$
|
(577
|
)
|
|
Capital expenditures
(b)
|
$
|
468
|
|
|
$
|
44
|
|
|
$
|
16
|
|
|
$
|
8
|
|
|
$
|
536
|
|
|
(a)
|
Includes other operating expenses and general and administrative expenses.
|
(b)
Includes accruals.
|
(c)
|
Unrealized loss on commodity derivative instruments.
|
|
(d)
|
Related to net gain on disposal of assets (see Note
6
).
|
|
(e)
|
Impairments associated with decision to not drill remaining Gulf of Mexico undeveloped leases.
|
|
(f)
|
Includes pension settlement loss of
$79 million
and severance related expenses associated with workforce reductions of
$8 million
(see Note
8
).
|
|
|
Six Months Ended June 30, 2015
|
||||||||||||||||||
|
|
|
|
Not Allocated
|
|
|
||||||||||||||
|
(In millions)
|
N.A. E&P
|
|
Int'l E&P
|
|
OSM
|
|
to Segments
|
|
Total
|
||||||||||
|
Sales and other operating revenues
|
$
|
1,843
|
|
|
$
|
393
|
|
|
$
|
372
|
|
|
$
|
(21
|
)
|
(c)
|
$
|
2,587
|
|
|
Marketing revenues
|
288
|
|
|
56
|
|
|
43
|
|
|
—
|
|
|
387
|
|
|||||
|
Total revenues
|
2,131
|
|
|
449
|
|
|
415
|
|
|
(21
|
)
|
|
2,974
|
|
|||||
|
Income from equity method investments
|
—
|
|
|
62
|
|
|
—
|
|
|
—
|
|
|
62
|
|
|||||
|
Net gain on disposal of assets and other income
|
11
|
|
|
14
|
|
|
1
|
|
|
1
|
|
|
27
|
|
|||||
|
Less:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Production expenses
|
381
|
|
|
131
|
|
|
382
|
|
|
—
|
|
|
894
|
|
|||||
|
Marketing costs
|
292
|
|
|
54
|
|
|
41
|
|
|
—
|
|
|
387
|
|
|||||
|
Exploration expenses
|
126
|
|
|
75
|
|
|
—
|
|
|
—
|
|
|
201
|
|
|||||
|
Depreciation, depletion and amortization
|
1,317
|
|
|
135
|
|
|
97
|
|
|
23
|
|
|
1,572
|
|
|||||
|
Impairments
|
—
|
|
|
—
|
|
|
—
|
|
|
44
|
|
(d)
|
44
|
|
|||||
|
Other expenses
(a)
|
216
|
|
|
42
|
|
|
18
|
|
|
251
|
|
(e)
|
527
|
|
|||||
|
Taxes other than income
|
128
|
|
|
—
|
|
|
10
|
|
|
7
|
|
|
145
|
|
|||||
|
Net interest and other
|
—
|
|
|
—
|
|
|
—
|
|
|
105
|
|
|
105
|
|
|||||
|
Income tax provision (benefit)
|
(112
|
)
|
|
24
|
|
|
(36
|
)
|
|
(26
|
)
|
(f)
|
(150
|
)
|
|||||
|
Segment income (loss) / Net income (loss)
|
$
|
(206
|
)
|
|
$
|
64
|
|
|
$
|
(96
|
)
|
|
$
|
(424
|
)
|
|
$
|
(662
|
)
|
|
Capital expenditures
(b)
|
$
|
1,484
|
|
|
$
|
245
|
|
|
$
|
37
|
|
|
$
|
14
|
|
|
$
|
1,780
|
|
|
(a)
|
Includes other operating expenses and general and administrative expenses.
|
|
(b)
|
Includes accruals.
|
|
(c)
|
Unrealized loss on commodity derivative instruments.
|
|
(d)
|
Proved property impairments (See Note
13
).
|
|
(e)
|
Includes pension settlement loss of $
81 million
and severance related expenses associated with workforce reductions of
$43 million
(see Note
8
).
|
|
(f)
|
Includes
$135 million
of deferred tax expense related to Alberta provincial corporate tax rate increase (see Note
9
).
|
11
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
8
. Defined Benefit Postretirement Plans
The following summarizes the components of net periodic benefit cost:
|
|
Three Months Ended June 30,
|
||||||||||||||
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||
|
(In millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
|
Service cost
|
$
|
6
|
|
|
$
|
12
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
Interest cost
|
10
|
|
|
13
|
|
|
2
|
|
|
2
|
|
||||
|
Expected return on plan assets
|
(13
|
)
|
|
(17
|
)
|
|
—
|
|
|
—
|
|
||||
|
Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
– prior service cost (credit)
|
(3
|
)
|
|
(2
|
)
|
|
(1
|
)
|
|
(1
|
)
|
||||
|
– actuarial loss
|
4
|
|
|
7
|
|
|
—
|
|
|
—
|
|
||||
|
Net settlement loss
(a)
|
31
|
|
|
64
|
|
|
—
|
|
|
—
|
|
||||
|
Net curtailment loss
(b)
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||
|
Net periodic benefit cost
|
$
|
35
|
|
|
$
|
77
|
|
|
$
|
2
|
|
|
$
|
4
|
|
|
|
Six Months Ended June 30,
|
||||||||||||||
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||
|
(In millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
|
Service cost
|
$
|
12
|
|
|
$
|
24
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
Interest cost
|
21
|
|
|
27
|
|
|
5
|
|
|
5
|
|
||||
|
Expected return on plan assets
|
(28
|
)
|
|
(36
|
)
|
|
—
|
|
|
—
|
|
||||
|
Amortization:
|
|
|
|
|
|
|
|
|
|
|
|||||
|
– prior service cost (credit)
|
(5
|
)
|
|
(1
|
)
|
|
(2
|
)
|
|
(2
|
)
|
||||
|
– actuarial loss
|
7
|
|
|
14
|
|
|
—
|
|
|
—
|
|
||||
|
Net settlement loss
(a)
|
79
|
|
|
81
|
|
|
—
|
|
|
—
|
|
||||
|
Net curtailment loss (gain)
(b)
|
—
|
|
|
1
|
|
|
—
|
|
|
(4
|
)
|
||||
|
Net periodic benefit cost
|
$
|
86
|
|
|
$
|
110
|
|
|
$
|
5
|
|
|
$
|
1
|
|
|
(a)
|
Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan's total service and interest cost for that year.
|
|
(b)
|
Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans.
|
During the
first six months of 2016
, we recorded the effects of settlements of our U.S. pension plans. As required, we remeasured the plans' assets and liabilities as of the applicable balance sheet dates. The cumulative effects of these events are included in the remeasurement and reflected in both the pension liability and net periodic benefit cost.
During the
first six months of 2016
, we made contributions of
$30 million
to our funded pension plans. We expect to make additional contributions up to an estimated
$34 million
to our funded pension plans over the remainder of
2016
. During the
first six months of 2016
, we made payments of
$37 million
and
$10 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 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 for the
first six months of 2016
and
2015
were
37%
and
18%
. In Libya, considerable uncertainty remains around the timing of future production and sales levels. Reliable estimates of
2016
and
2015
Libyan annual ordinary income from our operations could not be made, and the range of possible scenarios in the worldwide annual effective tax rate calculation demonstrates significant variability. Thus, the tax benefit applicable to Libyan ordinary loss was
12
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
recorded as a discrete item in the
first six months of 2016
and
2015
. For the
first six months of 2016
and
2015
, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss). Excluding Libya, the effective tax rates would be
36%
and
15%
for the
first six months of 2016
and
2015
. The change was driven by a shift in jurisdictional income and tax legislation enacted by the Alberta government on June 29, 2015 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.
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 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 June 30, 2015, we held short-term investments comprised of bank time deposits with original maturities of greater than three months and remaining maturities of less than twelve months. These short-term investments, which were classified as held-to-maturity investments and recorded at amortized cost, matured in the third quarter of 2015.
11
. Inventories
Liquid hydrocarbons, natural gas and bitumen are recorded at weighted average cost and carried at the lower of cost or market value. Supplies and other items consist principally of tubular goods and equipment which are valued at weighted average cost and reviewed periodically for obsolescence or impairment when market conditions indicate.
|
|
June 30,
|
|
December 31,
|
||||
|
(In millions)
|
2016
|
|
2015
|
||||
|
Liquid hydrocarbons, natural gas and bitumen
|
$
|
31
|
|
|
$
|
35
|
|
|
Supplies and other items
|
241
|
|
|
278
|
|
||
|
Inventories, at cost
|
$
|
272
|
|
|
$
|
313
|
|
12
. Property, Plant and Equipment, net of Accumulated Depreciation, Depletion and Amortization
|
|
June 30,
|
|
December 31,
|
||||
|
(In millions)
|
2016
|
|
2015
|
||||
|
North America E&P
|
$
|
13,965
|
|
|
$
|
15,226
|
|
|
International E&P
|
2,479
|
|
|
2,533
|
|
||
|
Oil Sands Mining
|
9,101
|
|
|
9,197
|
|
||
|
Corporate
|
112
|
|
|
105
|
|
||
|
Net property, plant and equipment
|
$
|
25,657
|
|
|
$
|
27,061
|
|
Our Libya operations continue to be impacted by civil unrest. Operations were interrupted in mid-2013 as a result of the shutdown of the Es-Sider crude oil terminal, and although temporarily re-opened during the second half of 2014, production remains shut-in. Earlier this year, an Internationally-backed Unity Government was established in Tripoli. During the second quarter, the two National Oil Companies agreed to unify and reportedly have begun preliminary discussions on re-opening the Es-Sider and other crude oil terminals which, if successful, will allow resumption of production operations at our Waha concessions. However, considerable uncertainty remains around the timing of future production and sales levels.
As of
June 30, 2016
, our net property, plant and equipment investment in Libya is
$775 million
, and total proved reserves (unaudited) in Libya as of December 31, 2015 are
235 million
barrels of oil equivalent ("mmboe"). We and our partners in the Waha concessions continue to assess the situation and the condition of our assets in Libya. Our periodic assessment of the carrying value of our net property, plant and equipment in Libya specifically considers the net investment in the assets, the duration of our concessions and the reserves anticipated to be recoverable in future periods. The undiscounted cash flows related to our Libya assets continue to exceed the carrying value of
$775 million
by a material amount. However, changes in
13
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
management's forecast assumptions may cause us to reassess our assets in Libya for impairment, and could result in non-cash impairment charges in the future.
Exploratory well costs capitalized greater than one year after completion of drilling were
$118 million
and
$85 million
as of
June 30, 2016
and
December 31, 2015
. The
$33 million
increase primarily relates to the Alba Block Sub Area B offshore Equatorial Guinea where the Rodo well reached total depth in the first quarter of 2015. We have since completed a seismic feasibility study and continue to finalize next steps in the Alba Block Sub Area B exploration program.
13
. Fair Value Measurements
Fair Values - Recurring
The following tables present assets and liabilities accounted for at fair value on a recurring basis as of
June 30, 2016
and
December 31, 2015
by fair value hierarchy level.
|
|
June 30, 2016
|
||||||||||||||
|
(In millions)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
Derivative instruments, assets
|
|
|
|
|
|
|
|
||||||||
|
Commodity
(a)
|
$
|
—
|
|
|
$
|
6
|
|
|
$
|
—
|
|
|
$
|
6
|
|
|
Interest rate
|
—
|
|
|
12
|
|
|
—
|
|
|
12
|
|
||||
|
Derivative instruments, assets
|
$
|
—
|
|
|
$
|
18
|
|
|
$
|
—
|
|
|
$
|
18
|
|
|
Derivative instruments, liabilities
|
|
|
|
|
|
|
|
||||||||
|
Commodity
(a)
|
$
|
—
|
|
|
$
|
70
|
|
|
$
|
—
|
|
|
$
|
70
|
|
|
Derivative instruments, liabilities
|
$
|
—
|
|
|
$
|
70
|
|
|
$
|
—
|
|
|
$
|
70
|
|
|
(a)
|
Derivative instruments are recorded on a net basis in the company's balance sheet (see Note
14
).
|
|
|
December 31, 2015
|
||||||||||||||
|
(In millions)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
Derivative instruments, assets
|
|
|
|
|
|
|
|
||||||||
|
Commodity
(a)
|
$
|
—
|
|
|
$
|
51
|
|
|
$
|
—
|
|
|
$
|
51
|
|
|
Interest rate
|
—
|
|
|
8
|
|
|
—
|
|
|
8
|
|
||||
|
Derivative instruments, assets
|
$
|
—
|
|
|
$
|
59
|
|
|
$
|
—
|
|
|
$
|
59
|
|
|
Derivative instruments, liabilities
|
|
|
|
|
|
|
|
||||||||
|
Commodity
(a)
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
1
|
|
|
Derivative instruments, liabilities
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
1
|
|
|
(a)
|
Derivative instruments are recorded on a net basis in the company's balance sheet (see Note
14
).
|
Commodity derivatives include three-way collars, two-way collars, call options and swaptions. These instruments are measured at fair value using either the Black-Scholes Model or the Black Model. Inputs to both models include commodity 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
14
for additional discussion of the types of derivative instruments we use.
Fair Values – Goodwill
Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. We estimate the fair value of our International E&P reporting unit using a combination of market and income approaches. The market approach referenced observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value, and valuation multiples of us and our peers from the investor analyst community. The income approach utilized discounted cash flows, which were based on forecasted assumptions. Key assumptions to the income approach include future liquid hydrocarbon and natural gas pricing, estimated quantities of liquid hydrocarbons and natural gas proved and probable reserves, estimated timing of production, discount rates, future capital requirements and operating expenses and tax rates. The assumptions used in the income approach
14
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
are consistent with those that management uses to make business decisions. These valuations methodologies represent Level 3 fair value measurements. We performed our annual impairment test in April 2016 and concluded no impairment was required. While the fair value of our International E&P reporting unit exceeded the book value, subsequent commodity price and/or common stock declines may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.
Fair Values- 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.
|
|
Six Months Ended June 30,
|
||||||||||||||
|
|
2016
|
|
2015
|
||||||||||||
|
(In millions)
|
Fair Value
|
|
Impairment
|
|
Fair Value
|
|
Impairment
|
||||||||
|
Long-lived assets held for use
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
17
|
|
|
$
|
44
|
|
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. Inputs to the fair value measurement include reserve and production estimates made by our reservoir engineers, estimated future commodity prices adjusted for quality and location differentials and forecasted operating expenses for the remaining estimated life of the reservoir.
During the second quarter of 2015, we recorded a non-cash impairment charge of
$44 million
related to 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.
Fair Values – Financial Instruments
Our current assets and liabilities include financial instruments, the most significant of which are receivables, long-term debt and payables. We believe the carrying values of our receivables and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our credit rating, and (3) our historical incurrence of and expected future insignificant bad debt expense, which includes an evaluation of counterparty credit risk.
The following table summarizes financial instruments, excluding receivables, payables and derivative financial instruments, and their reported fair values by individual balance sheet line item at
June 30, 2016
and
December 31, 2015
.
|
|
June 30, 2016
|
|
December 31, 2015
|
||||||||||||
|
|
Fair
|
|
Carrying
|
|
Fair
|
|
Carrying
|
||||||||
|
(In millions)
|
Value
|
|
Amount
|
|
Value
|
|
Amount
|
||||||||
|
Financial assets
|
|
|
|
|
|
|
|
||||||||
|
Other noncurrent assets
|
$
|
198
|
|
|
$
|
206
|
|
|
$
|
104
|
|
|
$
|
118
|
|
|
Total financial assets
|
$
|
198
|
|
|
$
|
206
|
|
|
$
|
104
|
|
|
$
|
118
|
|
|
Financial liabilities
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Other current liabilities
|
$
|
25
|
|
|
$
|
24
|
|
|
$
|
34
|
|
|
$
|
33
|
|
|
Long-term debt, including current portion
(a)
|
7,186
|
|
|
7,291
|
|
|
6,723
|
|
|
7,291
|
|
||||
|
Deferred credits and other liabilities
|
121
|
|
|
117
|
|
|
97
|
|
|
95
|
|
||||
|
Total financial liabilities
|
$
|
7,332
|
|
|
$
|
7,432
|
|
|
$
|
6,854
|
|
|
$
|
7,419
|
|
(a)
Excludes capital leases, debt issuance costs and interest rate swap adjustments.
15
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
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.
14
. Derivatives
For further information regarding the fair value measurement of derivative instruments, see Note
13
. 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.
|
|
June 30, 2016
|
|
|
||||||||||
|
(In millions)
|
Asset
|
|
Liability
|
|
Net Asset
|
|
Balance Sheet Location
|
||||||
|
Fair Value Hedges
|
|
|
|
|
|
|
|
||||||
|
Interest rate
|
$
|
12
|
|
|
$
|
—
|
|
|
$
|
12
|
|
|
Other noncurrent assets
|
|
Total Designated Hedges
|
$
|
12
|
|
|
$
|
—
|
|
|
$
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
|
June 30, 2016
|
|
|
||||||||||
|
(In millions)
|
Asset
|
|
Liability
|
|
Net Liability
|
|
Balance Sheet Location
|
||||||
|
Not Designated as Hedges
|
|
|
|
|
|
|
|
||||||
|
Commodity
|
$
|
6
|
|
|
$
|
39
|
|
|
$
|
33
|
|
|
Other current liabilities
|
|
Commodity
|
—
|
|
|
31
|
|
|
31
|
|
|
Deferred credits and other liabilities
|
|||
|
Total Not Designated as Hedges
|
$
|
6
|
|
|
$
|
70
|
|
|
$
|
64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
|
||||||||||
|
(In millions)
|
Asset
|
|
Liability
|
|
Net Asset
|
|
Balance Sheet Location
|
||||||
|
Fair Value Hedges
|
|
|
|
|
|
|
|
||||||
|
Interest rate
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
8
|
|
|
Other noncurrent assets
|
|
|
|
|
|
|
|
|
|
||||||
|
Not Designated as Hedges
|
|
|
|
|
|
|
|
||||||
|
Commodity
|
$
|
51
|
|
|
$
|
1
|
|
|
$
|
50
|
|
|
Other current assets
|
Derivatives Designated as Fair Value Hedges
The following table presents, by maturity date, information about our interest rate swap agreements, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.
|
|
June 30, 2016
|
|
December 31, 2015
|
||||||||
|
|
Aggregate Notional Amount
|
Weighted Average, LIBOR-Based,
|
|
Aggregate Notional Amount
|
Weighted Average, LIBOR-Based,
|
||||||
|
Maturity Dates
|
(in millions)
|
Floating Rate
|
|
(in millions)
|
Floating Rate
|
||||||
|
October 1, 2017
|
$
|
600
|
|
4.94
|
%
|
|
$
|
600
|
|
4.73
|
%
|
|
March 15, 2018
|
$
|
300
|
|
4.77
|
%
|
|
$
|
300
|
|
4.66
|
%
|
16
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
The pretax effects of derivative instruments designated as hedges of fair value in our consolidated statements of income are summarized in the table below. There is no ineffectiveness related to fair value hedges.
|
|
|
Gain (Loss)
|
||||||||||||||
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
(In millions)
|
Income Statement Location
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
|
Derivative
|
|
|
|
|
|
|
|
|
||||||||
|
Interest rate
|
Net interest and other
|
$
|
—
|
|
|
$
|
(2
|
)
|
|
$
|
4
|
|
|
$
|
3
|
|
|
Hedged Item
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Long-term debt
|
Net interest and other
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
(4
|
)
|
|
$
|
(3
|
)
|
Derivatives not Designated as Hedges
We have entered into multiple crude oil and natural gas derivatives indexed to NYMEX WTI and Henry Hub related to a portion of our forecasted North America E&P sales through December 2017. These commodity derivatives consist of three-way collars, two-way collars, call options and swaptions. Three-way collars consist of a sold call (ceiling), a purchased put (floor) and a sold put. The ceiling price is the maximum we will receive for the contract volumes, the floor is the minimum price we will receive, unless the market price falls below the sold put strike price. In this case, we receive the NYMEX WTI/Henry Hub price plus the difference between the floor and the sold put price. These commodity derivatives were not designated as hedges. The following table sets forth outstanding derivative contracts as of June 30, 2016 and the weighted average prices for those contracts:
|
Crude Oil
|
|||
|
|
|
Year Ending December 31,
|
|
|
|
Third Quarter
|
Fourth Quarter
|
2017
|
|
Three-Way Collars
|
|||
|
Volume (Bbls/day)
|
47,000
|
47,000
|
—
|
|
Price per Bbl:
|
|
|
|
|
Ceiling
|
$55.37
|
$55.37
|
—
|
|
Floor
|
$50.23
|
$50.23
|
—
|
|
Sold put
|
$40.96
|
$40.96
|
—
|
|
Sold call options
(a)
|
|
|
|
|
Volume (Bbls/day)
|
10,000
|
10,000
|
35,000
|
|
Price per Bbl
|
$72.39
|
$72.39
|
$61.91
|
|
Two-way Collars
|
|
|
|
|
Volume (Bbls/day)
|
10,000
|
10,000
|
—
|
|
Price per Bbl:
|
|
|
—
|
|
Ceiling
|
$50.00
|
$50.00
|
|
|
Floor
|
$41.55
|
$41.55
|
|
|
(a)
|
Call options settle monthly.
|
17
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
|
Natural Gas
|
|||
|
|
|
Year Ending December 31,
|
|
|
|
Third Quarter
|
Fourth Quarter
|
2017
|
|
Three-Way Collars
(a)
|
|
|
|
|
Volume (MMBtu/day)
|
20,000
|
20,000
|
40,000
|
|
Price per MMBtu
|
|
|
|
|
Ceiling
|
$2.93
|
$2.93
|
$3.28
|
|
Floor
|
$2.50
|
$2.50
|
$2.75
|
|
Sold put
|
$2.00
|
$2.00
|
$2.25
|
|
(a)
|
On our 2016 collars, the counterparty has the option to execute fixed-price swaps (swaptions) at a weighted average price of
$2.93
per MMBtu indexed to NYMEX Henry Hub, which is exercisable on December 22, 2016. If counterparty exercises, the term of the fixed-price swaps would be for the calendar year 2017 and, if all such options are exercised,
20,000
MMBtu per day.
|
The mark-to-market impact of these commodity derivative instruments appears in sales and other operating revenues in our consolidated statements of income for the three and six month periods ended June 30, 2016 was a net loss of
$88 million
and
$90 million
compared to a net loss of
$43 million
and
$17 million
for the same respective periods in 2015. Net cash received from settlements of commodity derivative instruments for the three and six month periods ended June 30, 2016 was $
14 million
and $
46 million
compared to $
4 million
for both of the respective periods in 2015.
15
. Incentive Based Compensation
Stock options, restricted stock awards and restricted stock units
The following table presents a summary of activity for the
first six months
of
2016
:
|
|
Stock Options
|
|
Restricted Stock Awards & Units
|
||||||||||
|
|
Number of
Shares
|
|
Weighted
Average
Exercise Price
|
|
Awards
|
|
Weighted
Average Grant
Date Fair Value
|
||||||
|
Outstanding at December 31, 2015
|
12,665,419
|
|
|
|
$29.97
|
|
|
4,017,344
|
|
|
|
$30.76
|
|
|
Granted
|
1,680,000
|
|
(a)
|
|
$7.22
|
|
|
5,233,984
|
|
|
|
$7.91
|
|
|
Options Exercised/Stock Vested
|
—
|
|
|
—
|
|
|
(1,148,953
|
)
|
|
|
$32.29
|
|
|
|
Canceled
|
(973,295
|
)
|
|
|
$25.76
|
|
|
(557,051
|
)
|
|
|
$23.20
|
|
|
Outstanding at June 30, 2016
|
13,372,124
|
|
|
|
$27.42
|
|
|
7,545,324
|
|
|
|
$15.23
|
|
(a)
The weighted average grant date fair value of stock option awards granted was
$1.97
per share.
Stock-based performance unit awards
During the
first six months
of
2016
, we granted
1,205,517
stock-based performance units to certain officers. The grant date fair value per unit was
$3.72
.
16
. Debt
Revolving Credit Facility
As of
June 30, 2016
, we had no borrowings against our revolving credit facility (the "Credit Facility"), as described below.
In March 2016, we increased our
$3.0 billion
unsecured Credit Facility by
$300 million
to a total of
$3.3 billion
.
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
June 30, 2016
, we were in compliance with this covenant with a debt-to-capitalization ratio of
28%
.
18
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
Debt Issuance
In the second quarter of 2015, we issued $
2 billion
aggregate principal amount of unsecured senior notes and used the aggregate net proceeds to repay our $
1 billion
0.90%
senior notes November 1, 2015, and for general corporate purposes.
17
. Reclassifications Out of Accumulated Other Comprehensive Loss
The following table presents a summary of amounts reclassified from accumulated other comprehensive loss:
18
. Stockholder's Equity
In March 2016, we issued
166,750,000
shares of our common stock, par value
$1
per share, at a price of
$7.65
per share, excluding underwriting discounts and commissions, for net proceeds of
$1,236 million
. The proceeds were used to strengthen our balance sheet and for general corporate purposes, including funding a portion of our Capital Program.
19
. Supplemental Cash Flow Information
|
|
Six Months Ended June 30,
|
||||||
|
(In millions)
|
2016
|
|
2015
|
||||
|
Net cash (used in) operating activities:
|
|
|
|
||||
|
Interest paid (net of amounts capitalized)
|
$
|
(177
|
)
|
|
$
|
(143
|
)
|
|
Income taxes paid to taxing authorities
|
(61
|
)
|
|
(165
|
)
|
||
|
Noncash investing activities:
|
|
|
|
|
|
||
|
Asset retirement cost increase
|
$
|
2
|
|
|
$
|
6
|
|
|
Asset retirement obligations assumed by buyer
|
83
|
|
|
—
|
|
||
20
. Commitments and Contingencies
We are a defendant in a number of legal and administrative proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims, tax disputes and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.
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.
21
. Subsequent Event
During the third quarter 2016, we executed an agreement to terminate our Gulf of Mexico deepwater drilling rig contract. As a result, we expect to recognize a termination payment of $
113
million in other operating expense in that quarter.
19
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the preceding consolidated financial statements and notes in Item 1.
Executive Overview
We are an independent global exploration and production company based in Houston, Texas with operations in North America, Europe and Africa and a focus on U.S. unconventional resource plays. Total proved reserves were 2.2 billion boe at December 31, 2015 and total assets were
$33 billion
at
June 30, 2016
.
Our significant strategic actions and financial results include the following:
|
•
|
Strengthened balance sheet
|
|
◦
|
At the end of the second quarter of 2016, we had
$5.9 billion
of liquidity, comprised of
$2.6 billion
in cash and an undrawn $3.3 billion revolving credit facility
|
|
◦
|
Cash-adjusted debt-to-capital ratio of
20%
at
June 30, 2016
, as compared with
25%
at December 31, 2015
|
|
•
|
Focused on cost reductions
|
|
◦
|
Production expenses per boe in the
second quarter
of 2016, as compared to the same period last year improved in the North America E&P segment by 13% to
$6.28
per boe and in the International E&P segment by 22% to
$5.09
per boe
|
|
◦
|
2016 Capital Program reduced by $100 million to $1.3 billion
|
|
◦
|
Eagle Ford completed well costs down 30% to $4.2 million versus the same quarter last year
|
|
•
|
Simplifying and concentrating portfolio
|
|
◦
|
Closed on the PayRock acquisition of STACK assets in Oklahoma for
$888 million
, funded with cash on hand
|
|
◦
|
Entered into agreements for over $1 billion of transaction value related to non-core asset sales; already received over $800 million in proceeds through August 1, 2016
|
|
•
|
Major Project updates
|
|
◦
|
Alba B3 compression project in E.G., designed to maintain the production plateau two additional years and extend field life up to eight years, was completed within budget and on schedule with first gas in July
|
|
◦
|
Outside-operated Gunflint development project in the Gulf of Mexico achieved first oil in July
|
|
•
|
Financial results
|
|
◦
|
Cash provided by operating activities of
$252 million
for the first six months of 2016, despite average crude oil and condensate price realizations of $35.27 per bbl.
|
|
◦
|
Net loss per share of
$0.20
in the
second quarter
of
2016
as compared to net loss per share of
$0.57
in the same period last year. Included in the second quarter 2016 net loss are:
|
|
▪
|
Unrealized losses from our commodity derivative instruments totaling
$91 million
, pre-tax
|
|
▪
|
Net gains on disposal of non-core assets totaling
$294 million
, pre-tax
|
|
▪
|
Non-cash impairments totaling
$141 million
, pre-tax, as a result of our decision not to drill any of our remaining Gulf of Mexico leases
|
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. Our focus continues on the strengthening of the balance sheet, the simplification and concentration of our portfolio and cost reductions which during the second quarter of 2016 included a reduction to our Capital Program of $100 million to $1.3 billion for the year.
20
Exploration Update
In September 2015, we announced our intention to scale back our conventional exploration program, with future exploration investment focused on fulfilling our existing commitments in the Gulf of Mexico and Gabon. In second quarter of
2016
, we made the decision to not drill our remaining Gulf of Mexico undeveloped leases. As a result, we recorded a non-cash impairment of $
141 million
in the second quarter of
2016
. Additionally, during the third quarter 2016, we executed an agreement to terminate our Gulf of Mexico deepwater drilling rig contract. As a result, we expect to recognize a termination payment of $
113
million in other operating expense in that 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 June 30,
|
|
Six Months Ended June 30,
|
||||||||
|
Net Sales Volumes
|
2016
|
|
2015
|
|
Increase
(Decrease) |
|
2016
|
|
2015
|
|
Increase
(Decrease) |
|
North America E&P
(mboed)
|
224
|
|
274
|
|
(18)%
|
|
232
|
|
278
|
|
(17)%
|
|
International E&P
(mboed)
|
120
|
|
108
|
|
11%
|
|
108
|
|
112
|
|
(4)%
|
|
Oil Sands Mining
(mbbld)
(a)
|
49
|
|
29
|
|
69%
|
|
54
|
|
44
|
|
23%
|
|
Total
(mboed)
|
393
|
|
411
|
|
(4)%
|
|
394
|
|
434
|
|
(9)%
|
North America E&P
Net sales volumes in the segment were lower in the second quarter and first six months of 2016 primarily as a result of decreased drilling and completion activity resulting in fewer wells brought to sales as well as 17 mboed relating to dispositions of certain non-core assets (Gulf of Mexico and East Texas, North Louisiana and Wilburton, Oklahoma) during the second half of 2015. The following tables provide details regarding net sales volumes, sales mix and operational drilling activity for our significant operations within this segment:
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||
|
Net Sales Volumes
|
2016
|
|
2015
|
|
Increase
(Decrease) |
|
2016
|
|
2015
|
|
Increase
(Decrease) |
|
Equivalent Barrels
(mboed)
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford
|
109
|
|
135
|
|
(19)%
|
|
114
|
|
141
|
|
(19)%
|
|
Oklahoma Resource Basins
|
27
|
|
24
|
|
13%
|
|
27
|
|
24
|
|
13%
|
|
Bakken
|
53
|
|
61
|
|
(13)%
|
|
55
|
|
59
|
|
(7)%
|
|
Other North America
(a)
|
35
|
|
54
|
|
(35)%
|
|
36
|
|
54
|
|
(33)%
|
|
Total North America E&P
|
224
|
|
274
|
|
(18)%
|
|
232
|
|
278
|
|
(17)%
|
21
|
|
Three Months Ended June 30, 2016
|
||||
|
Sales Mix - U.S. Resource Plays
|
Crude oil and condensate
|
|
Natural gas liquids
|
|
Natural gas
|
|
|
|
|
|
|
|
|
Eagle Ford
|
56%
|
|
21%
|
|
23%
|
|
Oklahoma Resource Basins
|
21%
|
|
29%
|
|
50%
|
|
Bakken
|
83%
|
|
9%
|
|
8%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
Gross Operated
|
|
|
|
|
|
|
|
|
Eagle Ford:
|
|
|
|
|
|
|
|
|
Wells drilled to total depth
|
40
|
|
59
|
|
98
|
|
147
|
|
Wells brought to sales
|
30
|
|
52
|
|
80
|
|
143
|
|
Oklahoma Resource Basins:
|
|
|
|
|
|
|
|
|
Wells drilled to total depth
|
6
|
|
5
|
|
11
|
|
13
|
|
Wells brought to sales
|
5
|
|
3
|
|
8
|
|
8
|
|
Bakken:
|
|
|
|
|
|
|
|
|
Wells drilled to total depth
|
—
|
|
5
|
|
3
|
|
25
|
|
Wells brought to sales
|
4
|
|
22
|
|
10
|
|
46
|
|
•
|
Eagle Ford
– Of the
30
gross operated wells brought to sales during the second quarter of 2016, 19 were Lower Eagle Ford, 3 were Upper Eagle Ford and 8 were Austin Chalk. Production decreases were due to lower completion activity with fewer gross operated wells brought to sales and reduced contribution from 2015 high-density pads drilled at tighter well spacing. Our average time to drill an Eagle Ford well in the
second quarter
2016
, spud-to-total depth, was 8 days, a decrease from 11 days in the same quarter last year as efficiency gains in drilling continued. Wells were drilled at an average rate of 2,400 feet per day.
|
|
•
|
Oklahoma Resource Basins
– Of the
5
gross operated wells brought to sales in the second quarter of 2016, 3 were in the SCOOP Woodford; 2 were in the STACK Meramec and all were extended laterals. We also participated in 16 outside-operated wells during the second quarter of 2016, 10 of which were in the SCOOP and 6 were in the STACK.
|
We closed on the Payrock acquisition in the STACK play in Oklahoma on
August 1, 2016
and continue to operate one drilling rig on the acreage with plans to add another rig late in the third quarter. This will bring the total rig count in Oklahoma to 4.
|
•
|
Bakken
– Of the
4
gross operated wells brought to sales in the second quarter of 2016, 2 were in the Middle Bakken formation and 2 in the Three Forks formation, all with higher intensity completions. We do not currently have an active drilling rig in the Bakken.
|
|
•
|
Other North America
– Net sales volumes declined in the second quarter of 2016 primarily due to the 2015 sales of the non-core assets in the Gulf of Mexico, East Texas, North Louisiana and Wilburton, Oklahoma. On June 30, we closed the sale of certain of our Wyoming upstream and midstream assets. Net sales volumes for all of our Wyoming assets were approximately 16 mboed for the second quarter and first half of 2016.
|
The Gunflint field, located in Mississippi Canyon block 948 in the Gulf of Mexico, achieved first production in July 2016. Full production is expected to reach at least 20 mboed gross with oil representing approximately 75% of the volumes produced. We hold an 18% non-operated working interest in the Gunflint field.
22
International E&P
Net sales volumes in the segment were higher in the second quarter of 2016 primarily as a result of planned turnaround and maintenance activities at the Alba field and E.G. LNG facilities in the second quarter of 2015. The following table provides details regarding net sales volumes for our significant operations within this segment.
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||
|
Net Sales Volumes
|
2016
|
|
2015
|
|
Increase
(Decrease)
|
|
2016
|
|
2015
|
|
Increase
(Decrease) |
|
Equivalent Barrels
(mboed)
|
|
|
|
|
|
|
|
|
|
|
|
|
Equatorial Guinea
|
101
|
|
89
|
|
13%
|
|
93
|
|
93
|
|
—%
|
|
United Kingdom
(a)
|
19
|
|
19
|
|
—%
|
|
15
|
|
19
|
|
(21)%
|
|
Total International E&P
|
120
|
|
108
|
|
11%
|
|
108
|
|
112
|
|
(4)%
|
|
Equity Method Investees
|
|
|
|
|
|
|
|
|
|
|
|
|
LNG
(mtd)
|
5,797
|
|
4,991
|
|
16%
|
|
5,060
|
|
5,629
|
|
(10)%
|
|
Methanol
(mtd)
|
1,303
|
|
673
|
|
94%
|
|
1,292
|
|
778
|
|
66%
|
|
Condensate & LPG
(boed)
|
11,306
|
|
8,586
|
|
32%
|
|
10,757
|
|
10,892
|
|
(1)%
|
|
(a)
|
Includes natural gas acquired for injection and subsequent resale of
5
mmcfd and
7
mmcfd for the
second quarter
s of
2016
and
2015
, and
5
mmcfd and
9
mmcfd for the first six months of
2016
and
2015
.
|
|
•
|
Equatorial Guinea
– Second quarter 2016 net sales were higher compared to the same quarter of 2015 due to lower planned turnaround and maintenance activities at the Alba field and E.G. LNG facilities. The Alba field compression project achieved first gas in July, which is expected to maintain the production plateau for an additional two years and extend field life up to eight years.
|
|
•
|
United Kingdom
– Net sales volumes in the first six months of 2016 were lower due to repair activities at the Brae Alpha facility following a process pipe failure in late 2015. Production was restored at the facility in late April. Higher overall production efficiency at the remaining Brae facilities and improved reliability from the outside-operated Foinaven field partially offset the Brae Alpha shut-in.
|
|
•
|
Libya
– Due to continued civil unrest, there were no liftings during the quarter, or any period presented. Earlier this year, an Internationally-backed Unity Government was established in Tripoli. During the second quarter, the two National Oil Companies agreed to unify and reportedly have begun preliminary discussions on re-opening the Es-Sider and other crude oil terminals which, if successful, will allow resumption of production operations at our Waha concessions. However, considerable uncertainty remains around the timing of future production and sales levels.
|
Oil Sands Mining
Our net synthetic crude oil sales volumes were
49
mbbld and
54
mbbld in the
second quarter and first six months of
2016
compared to
29
mbbld and
44
mbbld in the same periods of
2015
. Sales volumes increased in comparison to second quarter and first six months of 2015 which were adversely affected due to planned turnarounds at the base upgrader and Muskeg River Mine and unplanned downtime at the expansion upgrader. These sales volume increases were partially offset by a brief suspension of operations at both the Muskeg River and Jackpine mines in May 2016 in order to support emergency response efforts related to the Fort McMurray area wildfires in addition to the completion of planned maintenance activities at the Jackpine Mine and expansion upgrader that began in the first quarter 2016. Neither of the mines sustained any damage as a result of the wildfires. We hold a 20% non-operated working interest in the Athabasca Oil Sands Project.
23
Market Conditions
Prevailing prices for the crude oil, NGLs and natural gas that we produce significantly impact our revenues and cash flows. The benchmark prices for crude oil, NGLs and natural gas were lower in the
second quarter and first six months of
2016
as compared to the same period in
2015
; as a result, we experienced declines in our price realizations associated with those benchmarks. Additional detail on market conditions, including our average price realizations and benchmarks for crude oil, NGLs and natural gas relative to our operating segments, follows.
North America E&P
The following table presents our average price realizations and the related benchmarks for crude oil, NGLs and natural gas for the
second quarter and first six months of
2016
and
2015
.
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|||||||||||||
|
|
2016
|
|
2015
|
|
Decrease
|
|
2016
|
|
2015
|
|
Increase (Decrease)
|
|||||
|
Average Price Realizations
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Crude Oil and Condensate
(per bbl)
(b)
|
$40.77
|
|
$52.63
|
|
(23)%
|
|
$34.21
|
|
$47.11
|
|
(27
|
)%
|
||||
|
Natural Gas Liquids
(per bbl)
|
14.84
|
|
14.77
|
|
—%
|
|
11.43
|
|
|
14.60
|
|
|
(22
|
)%
|
||
|
Total Liquid Hydrocarbons
(per bbl)
|
35.07
|
|
45.96
|
|
(24)%
|
|
29.32
|
|
|
41.37
|
|
|
(29
|
)%
|
||
|
Natural Gas
(per mcf)
|
1.96
|
|
2.76
|
|
(29)%
|
|
1.99
|
|
|
2.88
|
|
|
(31
|
)%
|
||
|
Benchmarks
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
WTI crude oil
(per bbl)
|
$45.64
|
|
$57.95
|
|
(21)%
|
|
|
$39.78
|
|
|
|
$53.34
|
|
|
(25
|
)%
|
|
LLS crude oil
(per bbl)
|
47.35
|
|
62.94
|
|
(25)%
|
|
41.49
|
|
|
57.97
|
|
|
(28
|
)%
|
||
|
Mont Belvieu NGLs
(per bbl)
(c)
|
17.52
|
|
17.65
|
|
(1)%
|
|
15.78
|
|
|
18.02
|
|
|
(12
|
)%
|
||
|
Henry Hub natural gas
(per mmbtu)
|
1.95
|
|
2.64
|
|
(26)%
|
|
2.02
|
|
|
2.81
|
|
|
(28
|
)%
|
||
|
(a)
|
Excludes gains or losses on commodity derivative instruments.
|
|
(b)
|
Inclusion of realized gains on crude oil derivative instruments would have increased average realizations by
$0.12
per bbl and
$0.06
per bbl for the
second quarter
2016
and
2015
, and
$0.91
per bbl and
$0.14
per bbl for the first six months of
2016
and
2015
. Inclusion of realized gains on natural gas derivative instruments would have increased average realizations by $0.02 per mcf and $0.01 per mcf for the second quarter and first six months of 2016.
|
|
(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
second quarter and first six months of
2016
and
2015
.
|
(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 E.G. is condensate, which receives lower prices than crude oil.
24
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 at market prices and natural gas at fixed prices under long-term contracts, with our share of their income/loss reflected in the income from equity method investments line 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
second quarter and first six months of
2016
and
2015
.
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|||||||||||||
|
|
2016
|
|
2015
|
|
Decrease
|
|
2016
|
|
2015
|
|
Increase (Decrease)
|
|||||
|
Average Price Realizations
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Synthetic Crude Oil
(per bbl)
|
$40.88
|
|
$52.46
|
|
(22%)
|
|
|
$32.94
|
|
|
|
$44.33
|
|
|
(26
|
%)
|
|
Benchmarks
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
WTI crude oil
(per bbl)
|
$45.64
|
|
$57.95
|
|
(21%)
|
|
|
$39.78
|
|
|
|
$53.34
|
|
|
(25
|
%)
|
|
WCS crude oil
(per bbl)
(a)
|
32.29
|
|
46.35
|
|
(30%)
|
|
25.75
|
|
|
40.13
|
|
|
(36
|
%)
|
||
|
(a)
|
Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.
|
25
Results of Operations
Three Months Ended June 30, 2016
vs.
Three Months Ended June 30, 2015
Sales and other operating revenues, including related party
are presented by segment in the table below:
|
|
Three Months Ended June 30,
|
||||||
|
(In millions)
|
2016
|
|
2015
|
||||
|
Sales and other operating revenues, including related party
|
|
|
|
||||
|
North America E&P
|
$
|
617
|
|
|
$
|
993
|
|
|
International E&P
|
159
|
|
|
211
|
|
||
|
Oil Sands Mining
|
185
|
|
|
147
|
|
||
|
Segment sales and other operating revenues, including related party
|
$
|
961
|
|
|
$
|
1,351
|
|
|
Unrealized (loss) gain on commodity derivative instruments
|
(91
|
)
|
|
(44
|
)
|
||
|
Sales and other operating revenues, including related party
|
$
|
870
|
|
|
$
|
1,307
|
|
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.
|
(a)
|
Three months ended June 30, 2016 includes a net sales volume reduction of 17 mboed related to dispositions in the Gulf of Mexico and other conventional onshore U.S. production.
|
Marketing revenues
decreased
$94 million
in the
second quarter of 2016
from the comparable prior-year period. Marketing activities include the purchase of commodities from third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points. Since the volume of marketing activity is based on market dynamics, it can fluctuate from period to period. The decreases are related primarily to lower marketed volumes in North America E&P and OSM, which were further compounded by a lower commodity price environment.
Income from equity method investments
increased
$
11 million
in the
second quarter of 2016
from the comparable
2015
period. The increase is primarily due to an increase in net sales volumes as 2015 volumes were lower because of planned turnaround and maintenance activities at the Alba field and E.G. LNG facilities.
Net gain on disposal of assets
in the
second quarter of 2016
was primarily related to the sale of our Wyoming upstream and midstream assets and West Texas acreage. See Note
6
to the consolidated financial statements for information about dispositions.
Production expenses
decreased
$100 million
. North America E&P declined $50 million primarily due to lower operational, maintenance and labor costs, coupled with the disposition of our producing assets in the Gulf of Mexico and East Texas, North Louisiana and Wilburton, Oklahoma gas assets. International E&P declined $8 million primarily as a result of lower project and labor costs in the U.K. and 2015 also includes costs arising from planned flowline maintenance at the outside operated Foinaven field; these declines were partially offset by increased costs resulting from higher net sales volumes. OSM
26
decreased $42 million primarily due to lower turnaround costs and
continued cost management, specifically staffing and contract labor.
The
second quarter
of
2016
production expense rate (expense per boe) for North America E&P declined as cost reductions occurred at a rate faster than our production decline. The expense rate for International E&P declined due to an increase in volumes, combined with reduced maintenance and project costs in the U.K. The OSM expense rate decreased as a result of higher sales volumes and lower production expenses, as discussed above.
The following table provides production expense rates for each segment:
|
|
Three Months Ended June 30,
|
||||||
|
($ per boe)
|
2016
|
|
2015
|
||||
|
Production Expense Rate
|
|
|
|
||||
|
North America E&P
|
|
$6.28
|
|
|
|
$7.19
|
|
|
International E&P
|
|
$5.09
|
|
|
|
$6.51
|
|
|
Oil Sands Mining
(a)
|
|
$39.02
|
|
|
|
$78.24
|
|
|
(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
$94 million
in the
second quarter of 2016
from the comparable
2015
period, consistent with the marketing revenues changes discussed above.
Exploration expenses
increased
$78 million
primarily as a result of our decision to not drill any of our remaining Gulf of Mexico undeveloped leases. The following table summarizes the components of exploration expenses:
|
|
Three Months Ended June 30,
|
||||||
|
(In millions)
|
2016
|
|
2015
|
||||
|
Exploration Expenses
|
|
|
|
||||
|
Unproved property impairments
|
$
|
133
|
|
|
$
|
40
|
|
|
Dry well costs
|
22
|
|
|
41
|
|
||
|
Geological and geophysical
|
—
|
|
|
12
|
|
||
|
Other
|
34
|
|
|
18
|
|
||
|
Total exploration expenses
|
$
|
189
|
|
|
$
|
111
|
|
Depreciation, depletion and amortization
decreased
$190 million
primarily as a result of production volume decreases, a higher proved reserve base in Eagle Ford in the second half of 2015 and as a result of the non-core asset dispositions in 2015. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, proved reserve and production volumes have an impact on DD&A expense.
The DD&A rate (expense per boe), which is impacted by changes in reserves, capitalized costs, and sales volume mix by field, can also cause changes to our DD&A. The following table provides DD&A rates for each segment. The DD&A rate for North America E&P decreased primarily as a result of a higher proved reserve base in Eagle Ford in the second half of 2015. The DD&A rate for International E&P declined due to lower asset retirement costs, with cost estimates refined in the fourth quarter of 2015. The DD&A rate for OSM declined as a result of a higher proved reserve base in the fourth quarter of 2015.
Impairments
decreased $44 million in the
second quarter of 2016
as a result of the second quarter of 2015 non-cash impairment charge related to East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets in anticipation of the sale in 2015. See Note
13
to the consolidated financial statements for discussion of the impairment.
27
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, decreased $
39 million
in the
second quarter of 2016
. The following table summarizes the components of taxes other than income:
|
|
Three Months Ended June 30,
|
||||||
|
(In millions)
|
2016
|
|
2015
|
||||
|
Production and severance
|
$
|
25
|
|
|
$
|
40
|
|
|
Ad valorem
|
5
|
|
|
15
|
|
||
|
Other
|
9
|
|
|
23
|
|
||
|
Total
|
$
|
39
|
|
|
$
|
78
|
|
General and administrative expenses
decreased
$36 million
primarily due to lower pension settlement charges in the
second quarter of 2016
, which totaled
$31 million
, compared to
$64 million
in the prior year.
Net interest and other
increased
$28 million
primarily due to increased interest expense associated with our June 2015 debt issuance. See Note
16
to the consolidated financial statements for discussion of the June 2015 debt issuance.
Provision (benefit) for income taxes
reflects an effective tax rate of
29%
in the
second quarter
of
2016
, as compared to
2%
in the
second quarter
of
2015
.
Segment Income
(Loss)
Segment income (loss) represents income (loss) from operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments, unrealized gains or losses on commodity derivative instruments, or other items that affect comparability also are not allocated to operating segments.
The following table reconciles segment income (loss) to net income (loss):
|
|
Three Months Ended June 30,
|
||||||
|
(In millions)
|
2016
|
|
2015
|
||||
|
North America E&P
|
$
|
(70
|
)
|
|
$
|
(45
|
)
|
|
International E&P
|
55
|
|
|
41
|
|
||
|
Oil Sands Mining
|
(38
|
)
|
|
(77
|
)
|
||
|
Segment income (loss)
|
(53
|
)
|
|
(81
|
)
|
||
|
Items not allocated to segments, net of income taxes
|
(117
|
)
|
|
(305
|
)
|
||
|
Net income (loss)
|
$
|
(170
|
)
|
|
$
|
(386
|
)
|
North America E&P segment loss
increased
$25 million
after-tax primarily due to lower price realizations and sales volumes, which was partially offset by the impact of lower net sales volumes to DD&A, production costs and taxes other than income; and lower exploration expenses.
International E&P segment income
increased
$14 million
after-tax primarily due to decreased exploration expenses and an increase in income from equity investments, which were partially offset by lower price realizations.
Oil Sands Mining segment loss
decreased
$39 million
after-tax primarily due to higher sales volumes and lower production expenses, partially offset by lower price realizations and higher DD&A expense.
28
Results of Operations
Six Months Ended June 30, 2016
vs.
Six Months Ended June 30, 2015
Consolidated Results of Operation
Sales and other operating revenues, including related party
are presented by segment in the table below:
|
|
Six Months Ended June 30,
|
||||||
|
(In millions)
|
2016
|
|
2015
|
||||
|
Sales and other operating revenues, including related party
|
|
|
|
||||
|
North America E&P
|
$
|
1,110
|
|
|
$
|
1,843
|
|
|
International E&P
|
255
|
|
|
393
|
|
||
|
Oil Sands Mining
|
333
|
|
|
372
|
|
||
|
Segment sales and other operating revenues, including related party
|
$
|
1,698
|
|
|
$
|
2,608
|
|
|
Unrealized loss on commodity derivative instruments
|
(114
|
)
|
|
(21
|
)
|
||
|
Sales and other operating revenues, including related party
|
$
|
1,584
|
|
|
$
|
2,587
|
|
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
Increase (Decrease) Related to
|
|
Six Months Ended
|
||||||||||
|
(In millions)
|
|
June 30, 2015
|
|
Price Realizations
|
|
Net Sales Volumes
|
|
June 30, 2016
|
||||||||
|
North America E&P Price-Volume Analysis
(a)
|
||||||||||||||||
|
Liquid hydrocarbons
|
|
$
|
1,633
|
|
|
$
|
(394
|
)
|
|
$
|
(279
|
)
|
|
$
|
960
|
|
|
Natural gas
|
|
188
|
|
|
(51
|
)
|
|
(24
|
)
|
|
113
|
|
||||
|
Realized gain on commodity
|
|
|
|
|
|
|
|
|
||||||||
|
derivative instruments
|
|
5
|
|
|
19
|
|
|
|
|
24
|
|
|||||
|
Other sales
|
|
17
|
|
|
|
|
|
|
13
|
|
||||||
|
Total
|
|
$
|
1,843
|
|
|
|
|
|
|
$
|
1,110
|
|
||||
|
International E&P Price-Volume Analysis
|
||||||||||||||||
|
Crude oil and condensate
|
|
|
|
|
|
|
|
|
||||||||
|
Natural gas liquids
|
|
|
|
|
|
|
|
|
||||||||
|
Liquid hydrocarbons
|
|
$
|
310
|
|
|
$
|
(90
|
)
|
|
$
|
(26
|
)
|
|
$
|
194
|
|
|
Natural gas
|
|
60
|
|
|
(17
|
)
|
|
—
|
|
|
43
|
|
||||
|
Other sales
|
|
23
|
|
|
|
|
|
|
18
|
|
||||||
|
Total
|
|
$
|
393
|
|
|
|
|
|
|
$
|
255
|
|
||||
|
Oil Sands Mining Price-Volume Analysis
|
||||||||||||||||
|
Synthetic crude oil
|
|
$
|
355
|
|
|
$
|
(112
|
)
|
|
$
|
81
|
|
|
$
|
324
|
|
|
Other sales
|
|
17
|
|
|
|
|
|
|
9
|
|
||||||
|
Total
|
|
$
|
372
|
|
|
|
|
|
|
$
|
333
|
|
||||
(a)
Six months ended June 30, 2016 includes a net sales volume reduction of 17 mboed related to dispositions in the Gulf of Mexico and other conventional onshore U.S. production.
Marketing revenues
for the
first six months
of
2016
decreased by
$240 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. Because the volume of marketing activity is based on market dynamics, it can fluctuate from period to period. The decrease is 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
$11 million
. The decrease is primarily due to lower net sales volumes as a result of planned downtime at E.G. as a result of the Alba field compression project which impacted our equity method plants, which was partially offset by planned turnaround and maintenance activities at the Alba field and E.G. LNG facilities in 2015. Also impacting the
first six months
of
2016
were lower price realizations for LPG at our Alba plant.
29
Net gain on disposal of assets
for the
first six months
of
2016
was primarily related to the sale of our Wyoming upstream and midstream assets and West Texas acreage. See Note
6
to the consolidated financial statements for information about dispositions.
Production expenses
for the
first six months
of
2016
decreased by
$216 million
compared to the same period of
2015
. North America E&P declined $118 million due to lower operational, maintenance and labor costs, coupled with the disposition of our producing assets in the Gulf of Mexico and East Texas, North Louisiana and Wilburton, Oklahoma gas assets. International E&P declined $22 million largely due to lower operational costs in the U.K. OSM decreased $76 million primarily due to continued cost management, specifically staffing and contract labor, lower turnaround costs, and a favorable exchange rate on expenses denominated in the Canadian Dollar.
The
first six months
of
2016
production expense rate (expense per boe) for North America E&P declined primarily due to cost reductions that occurred at a rate faster than our production decline. The International E&P expense rate decreased in the
first six months
of
2016
primarily due to reduced maintenance and project costs in the U.K. The OSM expense rate decreased in the
first six months
of
2016
primarily due to higher production coupled with lower operational costs.
|
|
|
Six Months Ended June 30,
|
||||||
|
($ per boe)
|
|
2016
|
|
2015
|
||||
|
Production Expense Rate
|
|
|
|
|
||||
|
North America E&P
|
|
|
$6.22
|
|
|
|
$7.57
|
|
|
International E&P
|
|
|
$5.53
|
|
|
|
$6.45
|
|
|
Oil Sands Mining
(a)
|
|
|
$33.42
|
|
|
|
$50.06
|
|
|
(a)
|
Production expense per synthetic crude oil barrel includes production costs, shipping and handling, taxes other than income and insurance costs and excludes pre-development costs.
|
Marketing costs
decreased
$241 million
in the
first six months
of
2016
from the comparable
2015
period, consistent with the marketing revenues changes discussed above.
Exploration expenses
were
$12 million
higher in the
first six months
of
2016
than in the comparable
2015
period primarily due to higher unproved property impairments, which were partially offset by lower dry well costs. Unproved property impairments were higher in
2016
primarily as a result of Gulf of Mexico leases that we decided not to drill. Dry well costs for the
first six months
of
2015
primarily consist of costs associated with 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. The following table summarizes the components of exploration expenses:
|
|
Six Months Ended June 30,
|
||||||
|
(In millions)
|
2016
|
|
2015
|
||||
|
Exploration Expenses
|
|
|
|
||||
|
Unproved property impairments
|
$
|
144
|
|
|
$
|
49
|
|
|
Dry well costs
|
22
|
|
|
99
|
|
||
|
Geological and geophysical
|
—
|
|
|
15
|
|
||
|
Other
|
47
|
|
|
38
|
|
||
|
Total exploration expenses
|
$
|
213
|
|
|
$
|
201
|
|
Depreciation, depletion and amortization
(“DD&A”) decreased
$402 million
in the
first six months
of
2016
from the comparable
2015
period primarily as a result of production volume decreases and a higher proved reserve base in Eagle Ford in the second half of 2015. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, volumes have an impact on DD&A expense.
The DD&A rate (expense per boe), which is impacted by field-level changes in sales volumes, 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 in the second half of 2015.
30
Impairments
decreased $43 million in the
first six months
of
2016
as a result of the second quarter of 2015 non-cash impairment charge related to East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets in anticipation of the sale in 2015. See Note
13
to the consolidated financial statements for discussion of the impairment.
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, decreased
$58 million
in the
first six months
of
2016
from the comparable
2015
period. The following table summarizes the components of taxes other than income:
|
|
Six Months Ended June 30,
|
||||||
|
(In millions)
|
2016
|
|
2015
|
||||
|
Production and severance
|
$
|
44
|
|
|
$
|
74
|
|
|
Ad valorem
|
19
|
|
|
31
|
|
||
|
Other
|
24
|
|
|
40
|
|
||
|
Total
|
$
|
87
|
|
|
$
|
145
|
|
General and administrative expenses
decreased
$56 million
in the
first six months
of
2016
compared to the same period in 2015. This decrease was primarily due to cost savings realized from the 2015 workforce reductions and corresponding severance expenses.
Provision (benefit) for income taxes
reflect effective tax rates of
37%
in the
first six months
of
2016
, as compared to
18%
from the comparable
2015
period. See Note
9
to the consolidated financial statements for discussion of the effective tax rate.
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):
|
|
Six Months Ended June 30,
|
||||||
|
(In millions)
|
2016
|
|
2015
|
||||
|
North America E&P
|
$
|
(265
|
)
|
|
$
|
(206
|
)
|
|
International E&P
|
59
|
|
|
64
|
|
||
|
Oil Sands Mining
|
(86
|
)
|
|
(96
|
)
|
||
|
Segment income (loss)
|
(292
|
)
|
|
(238
|
)
|
||
|
Items not allocated to segments, net of income taxes
|
(285
|
)
|
|
(424
|
)
|
||
|
Net income (loss)
|
$
|
(577
|
)
|
|
$
|
(662
|
)
|
North America E&P segment loss
increased
$59 million
after-tax in the
first six months
of
2016
from the comparable
2015
period primarily due to lower price realizations and sales volumes, which was partially offset by the impact of lower net sales volumes to DD&A, production costs and taxes other than income; and lower exploration expenses.
International E&P segment income
decreased
$5 million
after-tax in the
first six months
of
2016
from the comparable
2015
period primarily due to lower liquid hydrocarbon price realizations. These declines were partially offset by lower exploration, production and DD&A expenses.
Oil Sands Mining segment loss
decreased
$10 million
after-tax in the
first six months
of
2016
from the comparable
2015
period primarily due to higher sales volumes and lower production expenses, partially offset by lower price realizations and higher DD&A expense.
31
Critical Accounting Estimates
There have been no material changes or developments in the evaluation of the accounting estimates and the underlying assumptions or methodologies pertaining to our Critical Accounting Estimates disclosed in our Form 10-K for the year ended
December 31, 2015
, except as discussed below.
Fair Value Estimates - Goodwill
Goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. We performed our annual impairment test in April 2016 and concluded no impairment was required. While the fair value of our International E&P reporting unit exceeded book value, subsequent commodity price and/or common stock declines may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.
Estimated Quantities of Net Reserves
Our December 31, 2015 proved reserves were calculated using the unweighted average of closing benchmark prices nearest to the first day of each month within the 12-month period ("SEC pricing"). The table below provides the 2015 SEC pricing for certain benchmark prices as well as the unweighted average for the first eight months of 2016:
|
|
Unweighted 8-month 2016 Average
|
Unweighted 12-month 2015 Average
|
|
WTI Crude oil
|
$40.48
|
$50.28
|
|
Henry Hub natural gas
|
2.24
|
2.59
|
|
Brent crude oil
|
41.08
|
54.25
|
|
Natural gas liquids
|
14.92
|
17.32
|
Any significant future price change could have a material effect on the quantity and present value of our proved reserves. To the extent that commodity prices decrease during the remainder of 2016, a portion of our proved reserves could be deemed uneconomic and no longer classified as proved. This could impact both proved developed producing reserves as well as proved undeveloped reserves. Assuming lower commodity pricing in the remaining 4-months of 2016, a material volume of our proved reserves could become uneconomic and would have to be reclassified to non-proved reserve or resource category. In this scenario, our OSM proved reserves represent the largest risk to be reclassified to non-proved reserve or resource category. However, any impact of lower SEC pricing will likely be partially offset by continued cost reduction efforts. Also, any volumes reclassified to non-proved reserves could return to proved reserves as commodity prices improve. In the event the OSM proved reserves are reclassified to non-proved reserves or resource, their classification will have no impact on future plans for production.
Accounting Standards Not Yet Adopted
See Note
2
to the consolidated financial statements.
32
Cash Flows
The following table presents sources and uses of cash and cash equivalents:
|
|
Six Months Ended June 30,
|
|||||
|
(In millions)
|
2016
|
2015
|
||||
|
Sources of cash and cash equivalents
|
|
|
|
|
||
|
Operating activities
|
$
|
252
|
|
$
|
717
|
|
|
Disposals of assets
|
758
|
|
2
|
|
||
|
Borrowings
|
—
|
|
1,996
|
|
||
|
Common stock issuance
|
1,236
|
|
—
|
|
||
|
Other
|
39
|
|
43
|
|
||
|
Total sources of cash and cash equivalents
|
$
|
2,285
|
|
$
|
2,758
|
|
|
Uses of cash and cash equivalents
|
|
|
||||
|
Cash additions to property, plant and equipment
|
$
|
(753
|
)
|
$
|
(2,320
|
)
|
|
Deposit for acquisition
|
(89
|
)
|
—
|
|
||
|
Purchases of short-term investments
|
—
|
|
(925
|
)
|
||
|
Debt issuance costs
|
—
|
|
(19
|
)
|
||
|
Debt repayments
|
—
|
|
(34
|
)
|
||
|
Dividends paid
|
(77
|
)
|
(285
|
)
|
||
|
Other
|
(3
|
)
|
(1
|
)
|
||
|
Total uses of cash and cash equivalents
|
$
|
(922
|
)
|
$
|
(3,584
|
)
|
Cash flows generated from operating activities in the first six months of 2016 were lower as the downturn in the commodity cycle continued. This continued downward pressure on price realizations, coupled with the lower net sales volumes, continues to negatively impact our cash flows from operating activities. In the first six months of 2016, consolidated average oil and NGL price realizations were down by approximately 27% and consolidated net sales volumes declined by 9% as compared to the prior year.
Proceeds from disposals of assets are primarily from the sale of our Wyoming upstream and midstream assets; see Note
6
to the consolidated financial statements for further information concerning dispositions. Common stock issuance reflects net proceeds received in March 2016 from our public sale of common stock. See Liquidity and Capital Resources below for additional information.
Additions to property, plant and equipment are our most significant use of cash and cash equivalents and were lower in the first half of 2016 consistent with a reduced Capital Program as compared to the prior year. The following table shows capital expenditures by segment and reconciles to additions to property, plant and equipment as presented in the consolidated statements of cash flows (the table excludes an $89 million deposit paid into escrow related to the acquisition of PayRock assets - see Note
5
to the consolidated financial statements for further information related to this acquisition):
|
|
Six Months Ended June 30,
|
||||||
|
(In millions)
|
2016
|
|
2015
|
||||
|
North America E&P
|
$
|
468
|
|
|
$
|
1,484
|
|
|
International E&P
|
44
|
|
|
245
|
|
||
|
Oil Sands Mining
|
16
|
|
|
37
|
|
||
|
Corporate
|
8
|
|
|
14
|
|
||
|
Total capital expenditures
|
536
|
|
|
1,780
|
|
||
|
Decrease in capital expenditure accrual
|
217
|
|
|
540
|
|
||
|
Total use of cash and cash equivalents for property, plant and equipment
|
$
|
753
|
|
|
$
|
2,320
|
|
The Board of Directors approved a $0.05 per share dividend for the first quarter of 2016, which was paid in the second quarter of 2016. See Capital Requirements below for additional information about the second quarter dividend.
33
Liquidity and Capital Resources
In March 2016, we issued 166,750,000 shares of our common stock, par value $1 per share, at a price of $7.65 per share, excluding underwriting discounts and commissions, for net proceeds of
$1,236 million
. The proceeds were used to strengthen our balance sheet and for general corporate purposes, including funding a portion of our Capital Program.
Also in March 2016, we increased our $3 billion unsecured Credit Facility by $300 million to a total of $3.3 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the increase.
Our main sources of liquidity are cash and cash equivalents, sales of non-core assets, internally generated cash flow from operations, capital market transactions, and our $3.3 billion Credit Facility. Our working capital requirements are supported by these sources and we may draw on our $3.3 billion Credit Facility to meet short-term cash requirements, or issue debt or equity securities through the shelf registration statement discussed below as part of our longer-term liquidity and capital management. Because of the alternatives available to us as discussed above, we believe that our short-term and long-term liquidity is adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, and other amounts that may ultimately be paid in connection with contingencies.
Due to decreases in crude oil and U.S. natural gas prices, credit rating agencies reviewed companies in the industry earlier this year, including us. During the first quarter of 2016, our corporate credit rating was downgraded by: Standard & Poor's Ratings Services to BBB- (stable) from BBB (stable); by Fitch Ratings to BBB (negative) from BBB+ (stable); and by Moody's Investor Services, Inc. to Ba1 (negative) from Baa1 (stable). Any further rating downgrades could increase our future cost of financing or limit our ability to access capital, and result in additional collateral requirements. See Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2015 for a discussion of how a further downgrade in our credit ratings could affect us.
The June 23,
2016
referendum by British voters to exit the European Union (“Brexit”) provided uncertainty and potential volatility around European currencies, and resulted in a decline in the value of the British pound, as compared to the U.S. dollar and other currencies. Volatility in exchange rates may continue in the short term as the U.K. negotiates its exit from the European Union. A weaker British pound compared to the U.S. dollar during a reporting period causes local currency results of our U.K. operations to be translated into fewer U.S. dollars. For our U.K. operations a majority of our revenues are tied to global crude oil prices which are denominated in U.S. dollars while a significant portion of our operating and capital costs are denominated in British pounds. In addition, our U.K. operations have an asset retirement obligation, which represents a future cash commitment. In the longer term, any impact from Brexit on our U.K. operations will depend, in part, on the outcome of tariff, trade, regulatory, and other negotiations.
Capital Resources
Credit Arrangements and Borrowings
At
June 30, 2016
, we had no borrowings against our revolving credit facility.
At
June 30, 2016
, we had
$7.3 billion
in long-term debt outstanding, with our next debt maturity in the amount of $682 million due in the fourth quarter of 2017.
We do not have any triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit ratings.
Shelf Registration
We have a universal shelf registration statement filed with the SEC under which we, as a "well-known seasoned issuer" for purposes of SEC rules, have the ability to issue and sell an indeterminate amount of various types of equity and debt securities.
Asset Disposals
During the quarter, we announced the sale of our Wyoming upstream and midstream assets for proceeds of $870 million, before closing adjustments, of which approximately $690 million was received in the second quarter. The remaining asset sales are subject to the receipt of certain tribal consents and are expected to close before year end. The proceeds for the remaining asset sales were deposited into an escrow account by the buyer.
In March and April 2016, we entered into separate agreements to sell our 10% working interest in the outside-operated Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Colorado and certain undeveloped acreage in West Texas for a combined total of approximately $80 million in proceeds, before closing adjustments. We closed on certain of the asset sales during the six months ended June 30, 2016. The remaining asset sales are expected to close by year-end.
34
Cash-Adjusted Debt-To-Capital Ratio
Our cash-adjusted debt-to-capital ratio (total debt-minus-cash and cash equivalents to total debt-plus-equity-minus-cash and cash equivalents) was
20%
at
June 30, 2016
, compared to
25%
at
December 31, 2015
.
|
|
June 30,
|
|
December 31,
|
||||
|
(In millions)
|
2016
|
|
2015
|
||||
|
Long-term debt due within one year
|
$
|
1
|
|
|
$
|
1
|
|
|
Long-term debt
|
7,280
|
|
|
7,276
|
|
||
|
Total debt
|
$
|
7,281
|
|
|
$
|
7,277
|
|
|
Cash and cash equivalents
|
$
|
2,584
|
|
|
$
|
1,221
|
|
|
Equity
|
$
|
19,153
|
|
|
$
|
18,553
|
|
|
Calculation:
|
|
|
|
|
|
||
|
Total debt
|
$
|
7,281
|
|
|
$
|
7,277
|
|
|
Minus cash and cash equivalents
|
2,584
|
|
|
1,221
|
|
||
|
Total debt minus cash, cash equivalents
|
$
|
4,697
|
|
|
$
|
6,056
|
|
|
Total debt
|
$
|
7,281
|
|
|
$
|
7,277
|
|
|
Plus equity
|
19,153
|
|
|
18,553
|
|
||
|
Minus cash and cash equivalents
|
2,584
|
|
|
1,221
|
|
||
|
Total debt plus equity minus cash, cash equivalents
|
$
|
23,850
|
|
|
$
|
24,609
|
|
|
Cash-adjusted debt-to-capital ratio
|
20
|
%
|
|
25
|
%
|
||
Capital Requirements
We closed on our purchase agreement of PayRock for
$888 million
, as discussed in Note
5
to the consolidated financial statements. We expect our Capital Program for full-year 2016 to be $1.3 billion, or $100 million lower than the original budget, which includes the increased activity from the PayRock acquisition.
On July 27, 2016, our Board of Directors approved a dividend of
$0.05
per share for the
second quarter of 2016
payable September 12, 2016 to stockholders of record at the close of business on August 17, 2016.
As of
June 30, 2016
, we plan to make contributions of up to
$34 million
to our funded pension plans during the remainder of 2016.
Contractual Cash Obligations
As of
June 30, 2016
, there are no material changes to our consolidated cash obligations to make future payments under existing contracts, as disclosed in our 2015 Annual Report on Form 10-K, except for the agreement we entered into to acquire PayRock as described above, which was paid with cash on hand.
During the third quarter we executed an agreement to terminate our Gulf of Mexico deepwater drilling rig contract, as a result we expect to make a termination payment of $
113
million during the third quarter of 2016.
|
|
|
|
|
|
|
|
|
|
|
Environmental Matters and Other Contingencies
In July 2015, we received a request for information from the EPA under Section 114 of the Clean Air Act regarding several tank batteries used in our Bakken operations. Beginning in the second quarter of 2016, we have been in settlement discussions with the State of North Dakota’s Department of Health regarding potential noncompliance with the Clean Air Act, North Dakota Century Code Air Pollution Control provisions, and implementing regulations. To date, no federal or state enforcement action has been commenced in connection with this matter. We anticipate that resolution of this matter will result in civil or administrative penalties of an undetermined amount and require us to undertake corrective actions which may increase our development and/or operating costs. We do not believe that any penalties or corrective action expenditures that may result from this matter will have a material adverse effect on our financial position, results of operation or cash flows.
35
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, including without limitation statements regarding our future performance, business strategy, reserve estimates, asset quality, production guidance, drilling plans, capital plans, cost and expense estimates, assets acquisitions and sales, future financial position, and other plans and objectives for future operations, are forward-looking statements. Words such as “anticipate,” “believe,” "could," “estimate,” “expect,” “forecast,” "guidance," "intend," "may," “plan,” “project,” “seek,” “should,” "target," "will," “would” or similar words may be used to identify forward-looking statements; however, the absence of these words does not mean that the statements are not forward-looking. While we believe our assumptions concerning future events are reasonable, a number of factors could cause results to differ materially from those projected, including, but not limited to:
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•
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conditions in the oil and gas industry, including supply/demand levels and the resulting impact on price;
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•
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changes in expected reserve or production levels;
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•
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changes in economic conditions in the jurisdictions in which we operate, including changes in foreign currency exchange rates, interest rates, inflation rates, and global and domestic market conditions;
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•
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capital available for exploration and development;
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•
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risks related to our hedging activities;
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•
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our level of success in integrating acquisitions;
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•
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well production timing;
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•
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drilling and operating risks;
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•
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availability of materials and labor;
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•
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difficulty in obtaining necessary approvals and permits;
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•
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non-performance by third parties of contractual obligations;
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•
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unforeseen hazards such as weather conditions;
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•
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political conditions and developments, including political instability, acts of war or terrorist acts, and the governmental or military response thereto;
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•
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cyber-attacks;
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•
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changes in safety, health, environmental, tax and other regulations;
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|
•
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other geological, operating and economic considerations; and
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•
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the risk factors, forward-looking statements and challenges and uncertainties described in our 2015 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other filings with the SEC.
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All forward-looking statements included in this report are based on information available to us on the date of this report. We undertake no obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.
36
Item 3. Quantitative and Qualitative Disclosures About Market Risk
For a detailed discussion of our risk management strategies and our derivative instruments, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk in our 2015 Annual Report on Form 10-K. Notes
13
and
14
to the consolidated financial statements include 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.
Commodity Price Risk
During the first six months of 2016, we entered into crude oil and natural gas derivatives, indexed to NYMEX WTI and Henry Hub, related to a portion of our forecasted North America E&P sales. The following tables provide a summary of open positions as of
June 30, 2016
and the weighted average price for those contracts:
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Crude Oil
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|||
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Year Ending December 31,
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Third Quarter
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Fourth Quarter
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2017
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Three-Way Collars
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|||
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Volume (Bbls/day)
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47,000
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47,000
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—
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Price per Bbl:
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Ceiling
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$55.37
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$55.37
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—
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Floor
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$50.23
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$50.23
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—
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Sold put
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$40.96
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$40.96
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—
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Sold call options
(a)
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Volume (Bbls/day)
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10,000
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10,000
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35,000
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Price per Bbl
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$72.39
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$72.39
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$61.91
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Two-way Collars
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Volume (Bbls/day)
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10,000
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10,000
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—
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Price per Bbl:
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|
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—
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Ceiling
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$50.00
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$50.00
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Floor
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$41.55
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$41.55
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(a)
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Call options settle monthly.
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Natural Gas
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|||
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Year Ending December 31,
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Third Quarter
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Fourth Quarter
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2017
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Three-Way Collars
(a)
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Volume (MMBtu/day)
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20,000
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20,000
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40,000
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Price per MMBtu
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Ceiling
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$2.93
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$2.93
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$3.28
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Floor
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$2.50
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$2.50
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$2.75
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Sold put
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$2.00
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$2.00
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$2.25
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(a)
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On our 2016 collars, the counterparty has the option to execute fixed-price swaps (swaptions) at a weighted average price of
$2.93
per MMBtu indexed to NYMEX Henry Hub, which is exercisable on December 22, 2016. If counterparty exercises, the term of the fixed-price swaps would be for the calendar year 2017 and, if all such options are exercised,
20,000
MMBtu per day.
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37
The following table provides a sensitivity analysis of the projected incremental effect on income (loss) from operations of a hypothetical 10% change in NYMEX WTI and Henry Hub prices on our open commodity derivative instruments as of
June 30, 2016
.
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(In millions)
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Hypothetical Price Increase of 10%
|
Hypothetical Price Decrease of 10%
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||||
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|
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||||
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Crude oil derivatives
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$
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(32
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)
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$
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73
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|
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Natural gas derivatives
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(5
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)
|
5
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||
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Total
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$
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(37
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)
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$
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78
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Interest Rate Risk
Sensitivity analysis of the incremental effect of a hypothetical 10% change in interest rates on financial assets and liabilities as of
June 30, 2016
, is provided in the following table.
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(a)
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Fair value of cash and cash equivalents, receivables, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.
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(b)
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Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.
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(c)
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Excludes capital leases.
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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
June 30, 2016
.
During the
second quarter of 2016
, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
38
Part II – OTHER INFORMATION
Item 1. Legal and Administrative Proceedings
We are a defendant in a number of legal and administrative proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims, tax disputes and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.
In July 2015, we received a request for information from the EPA under Section 114 of the Clean Air Act regarding several tank batteries used in our Bakken operations. Beginning in the second quarter of 2016, we have been in settlement discussions with the State of North Dakota’s Department of Health regarding potential noncompliance with the Clean Air Act, North Dakota Century Code Air Pollution Control provisions, and implementing regulations. To date, no federal or state enforcement action has been commenced in connection with this matter. We anticipate that resolution of this matter will result in civil or administrative penalties of an undetermined amount and require us to undertake corrective actions which may increase our development and/or operating costs. We do not believe that any penalties or corrective action expenditures that may result from this matter will have a material adverse effect on our financial position, results of operation or cash flows.
Item 1A. Risk Factors
We are subject to various risks and uncertainties in the course of our business. There have been no material changes to the risk factors under Item 1A. Risk Factors in our
2015
Annual Report on Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table provides information about repurchases by Marathon Oil of its common stock during the quarter ended
June 30, 2016
.
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|
Total Number of
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|
Average Price
|
|
Total Number of
Shares Purchased
as Part of
Publicly Announced
|
|
Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
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|||
|
Period
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Shares Purchased
(a)
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|
Paid per Share
|
|
Plans or Programs
|
|
Plans or Programs
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|||
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04/01/16 - 04/30/16
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103,922
|
|
|
$10.97
|
|
—
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|
|
n/a
|
|
|
05/01/16 - 05/31/16
|
141,243
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|
|
13.56
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|
|
—
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|
|
n/a
|
|
06/01/16 - 06/30/16
|
486
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|
|
13.00
|
|
|
—
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|
|
n/a
|
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Total
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245,651
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|
|
$12.46
|
|
—
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|
|
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|
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(a)
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245,651
shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.
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Item 6. Exhibits
The information required by this Item 6 is set forth in the Exhibit Index accompanying this Form 10-Q.
39
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.
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August 4, 2016
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MARATHON OIL CORPORATION
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By:
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/s/ Gary E. Wilson
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Gary E. Wilson
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Vice President, Controller and Chief Accounting Officer
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(Duly Authorized Officer)
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40
Exhibit Index
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Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
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|||||
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Exhibit Number
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|
Exhibit Description
|
Form
|
|
Exhibit
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|
Filing Date
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|
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3.1
|
|
Restated Certificate of Incorporation of Marathon Oil Corporation
|
10-Q
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|
3.1
|
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8/8/2013
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3.2
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|
Marathon Oil Corporation By-laws (Amended and restated as of February 24, 2016)*
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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
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|
|
10.1
|
|
Marathon Oil Corporation 2016 Incentive Compensation Plan
|
14A
|
|
App. A
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|
4/07/2016
|
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12.1
|
|
Computation of Ratio of Earnings to Fixed Charges*
|
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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*
|
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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*
|
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32.1
|
|
Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350*
|
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32.2
|
|
Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350*
|
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101.INS
|
|
XBRL Instance Document*
|
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101.SCH
|
|
XBRL Taxonomy Extension Schema*
|
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101.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase*
|
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101.DEF
|
|
XBRL Taxonomy Extension Definition Linkbase*
|
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101.LAB
|
|
XBRL Taxonomy Extension Label Linkbase*
|
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101.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase*
|
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*
|
|
Filed herewith.
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