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 March 31, 2017
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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
þ
No
o
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
þ
No
o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth 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
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Smaller reporting company
o
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Emerging growth company
o
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(Do not check if a smaller reporting company)
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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
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No
þ
There were
849,991,741
shares of Marathon Oil Corporation common stock outstanding as of
April 30, 2017
.
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
2016
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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March 31,
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(In millions, except per share data)
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2017
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2016
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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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954
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$
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566
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Marketing revenues
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34
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46
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Income from equity method investments
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69
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14
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Net gain (loss) on disposal of assets
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1
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(60
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)
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Other income
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14
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4
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Total revenues and other income
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1,072
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570
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Costs and expenses:
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Production
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151
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187
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Marketing, including purchases from related parties
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34
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46
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Other operating
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89
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103
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Exploration
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28
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24
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Depreciation, depletion and amortization
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556
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549
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Impairments
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4
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1
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Taxes other than income
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39
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43
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General and administrative
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109
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151
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Total costs and expenses
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1,010
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1,104
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Income (loss) from operations
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62
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(534
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)
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Net interest and other
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(78
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)
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(79
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)
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Income (loss) from continuing operations before income taxes
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(16
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)
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(613
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)
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Provision (benefit) for income taxes
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34
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(253
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)
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Income (loss) from continuing operations
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(50
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)
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(360
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)
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Income (loss) from discontinued operations
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(4,907
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)
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(47
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)
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Net income (loss)
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$
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(4,957
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)
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$
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(407
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)
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Per basic share:
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Income (loss) from continuing operations
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$
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(0.06
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)
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$
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(0.49
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)
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Income (loss) from discontinued operations
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$
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(5.78
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)
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$
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(0.07
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)
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Net income (loss)
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$
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(5.84
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)
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$
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(0.56
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)
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Per diluted share:
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Income (loss) from continuing operations
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$
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(0.06
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)
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$
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(0.49
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)
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Income (loss) from discontinued operations
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$
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(5.78
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)
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$
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(0.07
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)
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Net income (loss)
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$
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(5.84
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)
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$
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(0.56
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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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0.05
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Weighted average common shares outstanding:
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Basic
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849
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730
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Diluted
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849
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730
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The accompanying notes are an integral part of these consolidated financial statements
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2
MARATHON OIL CORPORATION
Consolidated Statements of Comprehensive Income (Unaudited)
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Three Months Ended
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March 31,
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(In millions)
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2017
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2016
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Net income (loss)
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$
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(4,957
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)
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$
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(407
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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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4
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(24
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)
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Income tax provision (benefit)
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—
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9
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Postretirement and postemployment plans, net of tax
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4
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(15
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)
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Derivative hedges
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Net unrecognized gain
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1
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—
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Income tax provision
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—
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—
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Derivative hedges, net of tax
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1
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—
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Foreign currency hedges
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Net recognized gain reclassified to discontinued operations
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34
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—
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Income tax benefit (provision)
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(4
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)
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—
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Foreign currency hedges, net of tax
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30
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—
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Other comprehensive income (loss)
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35
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(15
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)
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Comprehensive income (loss)
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$
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(4,922
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)
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$
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(422
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)
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The accompanying notes are an integral part of these consolidated financial statements
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3
MARATHON OIL CORPORATION
Consolidated Balance Sheets (Unaudited)
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March 31,
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December 31,
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(In millions, except per share data)
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2017
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2016
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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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2,490
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$
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2,488
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Receivables, less reserve of $5 and $6
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751
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748
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Inventories
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145
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136
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Other current assets
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134
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66
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Current assets held for sale
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223
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227
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Total current assets
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3,743
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3,665
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Equity method investments
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906
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931
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Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $20,692 and $20,255
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16,533
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16,727
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Goodwill
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115
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115
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Other noncurrent assets
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698
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558
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Noncurrent assets held for sale
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2,542
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9,098
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Total assets
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$
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24,537
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$
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31,094
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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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1,081
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$
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967
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Payroll and benefits payable
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70
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129
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Accrued taxes
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81
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94
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Other current liabilities
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222
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243
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Long-term debt due within one year
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1,541
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686
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Current liabilities held for sale
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104
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121
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Total current liabilities
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3,099
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2,240
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Long-term debt
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5,723
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6,581
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Deferred tax liabilities
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800
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769
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Defined benefit postretirement plan obligations
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365
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345
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Asset retirement obligations
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1,622
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1,602
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Deferred credits and other liabilities
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221
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225
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Noncurrent liabilities held for sale
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123
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1,791
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Total liabilities
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11,953
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13,553
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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,
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 937 million shares (par value $1 per share,
1.1 billion shares authorized)
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937
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937
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Securities exchangeable into common stock – no shares issued or
outstanding (no par value, 29 million shares authorized)
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—
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—
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Held in treasury, at cost – 87 million and 90 million shares
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(3,314
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)
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(3,431
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)
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Additional paid-in capital
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7,336
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7,446
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Retained earnings
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7,673
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12,672
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Accumulated other comprehensive loss
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(48
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)
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(83
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)
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Total stockholders' equity
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12,584
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17,541
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Total liabilities and stockholders' equity
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$
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24,537
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$
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31,094
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The accompanying notes are an integral part of these consolidated financial statements
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4
MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows (Unaudited)
The accompanying notes are an integral part of these consolidated financial statements
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Three Months Ended
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March 31,
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(In millions)
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2017
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2016
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Operating activities:
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Net income (loss)
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$
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(4,957
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)
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$
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(407
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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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Discontinued operations
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4,907
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47
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Depreciation, depletion and amortization
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556
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549
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Impairments
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4
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1
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Unproved property impairments
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20
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11
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Net (gain) loss on disposal of assets
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(1
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)
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60
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Deferred income taxes
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14
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(295
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)
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Net (gain) loss on derivative instruments
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(77
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)
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2
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Net cash received (paid) in settlement of derivative instruments
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(7
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)
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32
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Pension and other postretirement benefits, net
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(9
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)
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14
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Stock based compensation
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14
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13
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Equity method investments, net
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13
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30
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Changes in:
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Current receivables
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(1
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)
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106
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Inventories
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(10
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)
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4
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Current accounts payable and accrued liabilities
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(1
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)
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(107
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)
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All other operating, net
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36
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9
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Net cash provided by operating activities from continuing operations
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501
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69
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Investing activities:
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Additions to property, plant and equipment
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(283
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)
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(441
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)
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Deposits for acquisitions
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(180
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)
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—
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Equity method investments - return of capital
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12
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14
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All other investing, net
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1
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19
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Net cash used in investing activities from continuing operations
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(450
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)
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(408
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)
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Financing activities:
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Common stock issuance
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—
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1,232
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Purchases of common stock
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(7
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)
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—
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Dividends paid
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(42
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)
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(34
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)
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All other financing, net
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(1
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)
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—
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Net cash provided by (used in) financing activities
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(50
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)
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1,198
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Cash Flow from Discontinued Operations:
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|
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Operating activities
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95
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|
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5
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Investing activities
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(9
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)
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(13
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)
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Changes in cash included in current assets held for sale
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(86
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)
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8
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Net increase in cash and cash equivalents of discontinued operations
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—
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|
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—
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Effect of exchange rate on cash and cash equivalents
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1
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|
|
—
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Net increase (decrease) in cash and cash equivalents
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2
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|
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859
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Cash and cash equivalents at beginning of period
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2,488
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1,119
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Cash and cash equivalents at end of period
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$
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2,490
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$
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1,978
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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.
These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our
2016
Annual Report on Form 10-K. The results of operations for the
first quarter of
2017
are not necessarily indicative of the results to be expected for the full year.
As a result of the announcement to divest of our Canadian business in the first quarter of 2017, we have reflected this business as discontinued operations in all periods presented. The disclosures in this report related to the results of operations and cash flows are presented on the basis of continuing operations, unless otherwise noted. Assets and liabilities are presented as held for sale in the consolidated balance sheets. This divestiture is discussed in further detail in Note
6
.
During the current period, we adopted the accounting standards update issued by the FASB in March 2016 pertaining to share-based payment transactions. See Note
2
for additional discussion. As a result of this adoption all cash payments, for withheld shares, made to taxing authorities on the employees' behalf will be presented within the financing activities section instead of the operating activities section of the statement of cash flows. We have elected the retrospective method for adoption of this update and the change in the statement of cash flows is not material for March 31, 2016. Excess tax benefits will be classified as an operating activity within the statement of cash flows on a prospective basis; as such, prior periods were not adjusted. See Note
2
for additional discussion.
We have reclassified certain prior year amounts between operating cash flow categories to present it on a basis comparable with the current year's presentation with no impact on net cash provided by operating activities.
2
. Accounting Standards
Not Yet Adopted
In March 2017, the FASB issued a new accounting standards update that will change how employers that sponsor defined pension and/ or other postretirement benefit plans present the net periodic benefit cost in the income statement. Employers will present the service cost component of net periodic benefit cost in the same income statement line item(s) as other employee compensation costs arising from services rendered during the period. Only the service cost component will be eligible for capitalization in assets. This standard is effective for us in the first quarter of 2018 and shall be applied on a retrospective basis. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it may have on our results of operations, financial position, or cash flows.
In February 2017, the FASB issued a new accounting standards update that clarifies the accounting for the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. The standard also clarifies that the derecognition of all businesses (except those related to conveyances of oil and gas mineral rights or contracts with customers) should be accounted for in accordance with the derecognition and deconsolidation guidance in Subtopic 810-10. This standard is effective for us in the first quarter of 2018 and will be applied using the modified retrospective approach. Early adoption is permitted. We plan to adopt this new standard in the first quarter of 2018 concurrently with the new revenue recognition standard. 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 2017, the FASB issued a new accounting standards update that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities would not represent a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue guidance. This standard is effective for us in the first quarter of 2018 and shall be applied on a prospective basis. Early adoption is permitted for certain transactions as described in the guidance. 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.
6
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
In January 2017, the FASB issued a new accounting standards update that eliminates the requirement to calculate the implied fair value of the goodwill (i.e., Step 2 of goodwill impairment test under the current guidance) to measure a goodwill impairment charge. The standard will require entities to record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value (i.e., measure the charge based on Step 1 under the current guidance). This standard is effective for us in the first quarter of 2020 and shall be applied on a prospective basis. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. 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 November 2016, the FASB issued a new accounting standards update that requires entities to show the changes in the total of cash, cash equivalents and restricted cash in the statement of cash flows. As a result, entities will no longer present transfers between cash and cash equivalents and restricted cash in the statement of cash flows. When cash, cash equivalents, and restricted cash are presented in more than one line item on the balance sheet, the standard requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. This reconciliation can be presented either on the face of the statement of cash flows or in the notes to the financial statements. This standard is effective for us in the first quarter of 2018 and shall be applied on a retrospective basis. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it may have on our consolidated statements of cash flows and related disclosures.
In August 2016, the FASB issued a new accounting standards update which seeks to reduce the existing diversity in practice in how certain transactions are classified in the statement of cash flows. This standard is effective for us in the first quarter of 2018 and shall be applied on a retrospective basis. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated statements of cash flows and related disclosures.
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 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 May 2014 and August 2015, 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 shall be applied retrospectively to each prior reporting period presented (“full retrospective method”) or with the cumulative effect of initially applying the update recognized at the date of initial application (“modified retrospective method”). While early adoption is permitted, we plan to adopt this new standard in the first quarter of 2018 using the modified retrospective method. We continue to assess our contracts that will be subject to this standard and assess the impact it will have on our consolidated results of operations, financial position or cash flows.
7
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
Recently Adopted
In March 2016, the FASB issued a new accounting standards update that changes several aspects of accounting for share-based payment transactions, including a requirement to recognize all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This standard was effective for us in the first quarter of 2017. The new standard requires a company to make a policy election on how it accounts for forfeitures; we elected to continue estimating forfeitures using the same methodology practiced prior to adoption of this standard. See Note
1
for the impact this standard has on the presentation of our financial statements.
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 was effective for us in the first quarter of 2017, and was applied prospectively. 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 (AOSP), in which we hold a
20%
undivided interest, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton, Alberta, Canada. Costs under this contract are accrued and recorded on a monthly basis, with current liabilities of
$2 million
recorded at
March 31, 2017
and
December 31, 2016
. This contract qualifies as a variable interest contractual arrangement, and the Corridor Pipeline qualifies as a VIE. We hold a variable interest but are not the primary beneficiary because our shipments are only
20%
of the total; therefore, the Corridor Pipeline is not consolidated by us. Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was
$472 million
as of
March 31, 2017
. 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. This contract will be transferred to the purchaser of our Canadian business upon closing in mid-2017. See Note
6
regarding dispositions. The accrued contract costs are reported within current liabilities held for sale.
|
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 in all years, provided the effect is not antidilutive. The per share calculations below exclude
12 million
and
13 million
stock options for the three months periods ended
March 31, 2017
and
March 31, 2016
that were antidilutive.
|
|
Three Months Ended March 31,
|
||||||
|
(In millions, except per share data)
|
2017
|
|
2016
|
||||
|
Income (loss) from operations
|
$
|
(50
|
)
|
|
$
|
(360
|
)
|
|
Income (loss) from discontinued operations
|
(4,907
|
)
|
|
(47
|
)
|
||
|
Net income (loss)
|
$
|
(4,957
|
)
|
|
$
|
(407
|
)
|
|
|
|
|
|
||||
|
Weighted average common shares outstanding
|
849
|
|
|
730
|
|
||
|
Per basic share:
|
|
|
|
||||
|
Income (loss) from continuing operations
|
$
|
(0.06
|
)
|
|
$
|
(0.49
|
)
|
|
Income (loss) from discontinued operations
|
$
|
(5.78
|
)
|
|
$
|
(0.07
|
)
|
|
Net income
|
$
|
(5.84
|
)
|
|
$
|
(0.56
|
)
|
|
Per diluted share:
|
|
|
|
||||
|
Income (loss) from continuing operations
|
$
|
(0.06
|
)
|
|
$
|
(0.49
|
)
|
|
Income (loss) from discontinued operations
|
$
|
(5.78
|
)
|
|
$
|
(0.07
|
)
|
|
Net income
|
$
|
(5.84
|
)
|
|
$
|
(0.56
|
)
|
8
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
5
. Acquisitions
In March 2017, we entered into separate agreements to acquire approximately
91,000
net acres in the Permian basin, including over
70,000
net acres in the Northern Delaware basin of New Mexico. We executed a purchase agreement with BC Operating, Inc. and other entities for
$1.1 billion
in cash, excluding closing adjustments, to acquire approximately
70,000
net surface acres and current production of approximately
5,000
net barrels of oil equivalent. We executed purchase agreements with Black Mountain Oil & Gas and other private sellers for
$700
million in cash, excluding closing adjustments, to acquire approximately
21,000
net surface acres. In March 2017, we paid
$180 million
in aggregate deposits into escrow related to these acquisitions. We closed on the acquisition from BC Operating, Inc. and other entities with cash on hand on May 1, 2017 and expect to close our remaining acquisition from Black Mountain Oil & Gas and other private sellers in the second quarter of 2017 with cash on hand.
|
6
.
|
Dispositions
|
Oil Sands Mining Segment
In March 2017 we entered into an agreement to sell our Canadian business, which includes our
20
percent non-operated interest in the AOSP to Shell and Canadian Natural Resources Limited for
$2.5 billion
in cash, excluding closing adjustments. Under the terms of the agreement,
$1.75 billion
, subject to closing adjustments, will be paid to us upon closing and the remaining proceeds will be paid in the first quarter of 2018. The sale is expected to close in mid-2017 concurrent with a related transaction between Shell and Canadian Natural Resources Limited. In the first quarter of 2017, we recorded a non-cash impairment charge of
$4.96 billion
after-tax primarily related to the property, plant and equipment of our Canadian business.
Our Canadian business is reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for all periods presented. The following table contains select amounts reported in our consolidated statements of income as discontinued operations:
|
|
Three Months Ended March 31,
|
|||||||
|
(In millions)
|
|
2017
|
|
2016
|
||||
|
Total revenues and other income
|
|
$
|
258
|
|
|
$
|
160
|
|
|
Costs and expenses:
|
|
|
|
|
||||
|
Production expenses
|
|
151
|
|
|
141
|
|
||
|
Depreciation, depletion and amortization
|
|
39
|
|
|
60
|
|
||
|
Impairments
|
|
6,636
|
|
|
—
|
|
||
|
Other
|
|
13
|
|
|
29
|
|
||
|
Total costs and expenses
|
|
6,839
|
|
|
230
|
|
||
|
Pretax income (loss) from discontinued operations
|
|
(6,581
|
)
|
|
(70
|
)
|
||
|
Provision (benefit) for income taxes
|
|
(1,674
|
)
|
|
(23
|
)
|
||
|
Income (loss) from discontinued operations
|
|
$
|
(4,907
|
)
|
|
$
|
(47
|
)
|
9
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
The following table presents the carrying value of the major categories of assets and liabilities of our Canadian business reported as discontinued operations and assets and liabilities from continuing operations, that are reflected as held for sale on our consolidated balance sheets at March 31, 2017 and December 31, 2016:
|
|
|
March 31,
|
|
December 31,
|
||||
|
(In millions)
|
|
2017
|
|
2016
|
||||
|
Assets held for sale
|
|
|
|
|
||||
|
Current assets:
|
|
|
|
|
||||
|
Cash and cash equivalents
|
|
$
|
87
|
|
|
$
|
1
|
|
|
Accounts receivables
|
|
111
|
|
|
129
|
|
||
|
Inventories
|
|
21
|
|
|
91
|
|
||
|
Other
|
|
3
|
|
|
5
|
|
||
|
Total current assets held for sale—discontinued operations
|
|
222
|
|
|
226
|
|
||
|
Total current assets held for sale—continuing operations
|
|
1
|
|
|
1
|
|
||
|
Total current assets held for sale
|
|
$
|
223
|
|
|
$
|
227
|
|
|
|
|
|
|
|
||||
|
Noncurrent assets:
|
|
|
|
|
||||
|
Property, plant and equipment, net
|
|
$
|
2,449
|
|
|
$
|
8,991
|
|
|
Other
|
|
92
|
|
|
106
|
|
||
|
Total noncurrent assets held for sale—discontinued operations
|
|
2,541
|
|
|
9,097
|
|
||
|
Total noncurrent assets held for sale—continuing operations
|
|
1
|
|
|
1
|
|
||
|
Total noncurrent assets held for sale
|
|
$
|
2,542
|
|
|
$
|
9,098
|
|
|
|
|
|
|
|
||||
|
Liabilities associated with assets held for sale
|
|
|
|
|
||||
|
Current liabilities:
|
|
|
|
|
||||
|
Accounts payable
|
|
$
|
90
|
|
|
$
|
111
|
|
|
Other
|
|
14
|
|
|
10
|
|
||
|
Total current liabilities held for sale—discontinued operations
|
|
$
|
104
|
|
|
$
|
121
|
|
|
Total current liabilities held for sale—continuing operations
|
|
—
|
|
|
—
|
|
||
|
Total current liabilities held for sale
|
|
$
|
104
|
|
|
$
|
121
|
|
|
|
|
|
|
|
||||
|
Noncurrent liabilities:
|
|
|
|
|
||||
|
Asset retirement obligations
|
|
$
|
96
|
|
|
$
|
95
|
|
|
Deferred tax liabilities
|
|
—
|
|
|
1,669
|
|
||
|
Other
|
|
20
|
|
|
20
|
|
||
|
Total noncurrent liabilities held for sale—discontinued operations
|
|
116
|
|
|
1,784
|
|
||
|
Total noncurrent liabilities held for sale—continuing operations
|
|
7
|
|
|
7
|
|
||
|
Total noncurrent liabilities held for sale
|
|
$
|
123
|
|
|
$
|
1,791
|
|
North America E&P Segment
As disclosed above we entered into an agreement to sell our Canadian business in March of 2017. This agreement includes interests in our exploration stage in-situ leases which were included within our North America E&P Segment. These interests have been reflected as discontinued operations and are included within the disclosure above.
10
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
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. We closed on certain of the asset sales and recognized a net pre-tax loss on sale of $
48 million
in the second quarter of 2016, with the remaining Piceance basin asset sale expected to close in the third quarter of 2017.
7
. Segment Information
We have
2
reportable operating segments. Both of these segments are organized and managed based upon 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 and
|
|
•
|
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.
|
Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”). Segment income (loss) represents income (loss) 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, 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.
As discussed in Note 6, we entered into an agreement to sell our Canadian business in March 2017. The Canadian business is reflected as discontinued operations and is excluded from segment information in all periods presented.
|
|
Three Months Ended March 31, 2017
|
||||||||||||||
|
|
|
Not Allocated
|
|
|
|||||||||||
|
(In millions)
|
N.A. E&P
|
|
Int'l E&P
|
|
to Segments
|
|
Total
|
||||||||
|
Sales and other operating revenues
|
$
|
674
|
|
|
$
|
203
|
|
|
$
|
77
|
|
(c)
|
$
|
954
|
|
|
Marketing revenues
|
6
|
|
|
28
|
|
|
—
|
|
|
34
|
|
||||
|
Total revenues
|
680
|
|
|
231
|
|
|
77
|
|
|
988
|
|
||||
|
Income from equity method investments
|
—
|
|
|
69
|
|
|
—
|
|
|
69
|
|
||||
|
Net gain on disposal of assets and other income
|
5
|
|
|
10
|
|
|
—
|
|
|
15
|
|
||||
|
Less:
|
|
|
|
|
|
|
|
||||||||
|
Production expenses
|
109
|
|
|
42
|
|
|
—
|
|
|
151
|
|
||||
|
Marketing costs
|
7
|
|
|
27
|
|
|
—
|
|
|
34
|
|
||||
|
Exploration expenses
|
26
|
|
|
2
|
|
|
—
|
|
|
28
|
|
||||
|
Depreciation, depletion and amortization
|
472
|
|
|
75
|
|
|
9
|
|
|
556
|
|
||||
|
Impairments
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
||||
|
Other expenses
(a)
|
107
|
|
|
21
|
|
|
70
|
|
(d)
|
198
|
|
||||
|
Taxes other than income
|
39
|
|
|
—
|
|
|
—
|
|
|
39
|
|
||||
|
Net interest and other
|
—
|
|
|
—
|
|
|
78
|
|
|
78
|
|
||||
|
Income tax provision (benefit)
|
—
|
|
|
50
|
|
|
(16
|
)
|
|
34
|
|
||||
|
Segment income (loss) / Income (loss) from continuing operations
|
$
|
(79
|
)
|
|
$
|
93
|
|
|
$
|
(64
|
)
|
|
$
|
(50
|
)
|
|
Capital expenditures
(b)
|
$
|
349
|
|
|
$
|
9
|
|
|
$
|
1
|
|
|
$
|
359
|
|
|
(a)
|
Includes other operating expenses and general and administrative expenses.
|
|
(b)
|
Includes accruals.
|
|
(c)
|
Unrealized gain on commodity derivative instruments.
|
|
(d)
|
Includes pension settlement loss of
$14 million
. See Note
8
.
|
11
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
|
|
Three Months Ended March 31, 2016
|
||||||||||||||
|
|
|
Not Allocated
|
|
|
|||||||||||
|
(In millions)
|
N.A. E&P
|
|
Int'l E&P
|
|
to Segments
|
|
Total
|
||||||||
|
Sales and other operating revenues
|
$
|
493
|
|
|
$
|
96
|
|
|
$
|
(23
|
)
|
(c)
|
$
|
566
|
|
|
Marketing revenues
|
31
|
|
|
15
|
|
|
—
|
|
|
46
|
|
||||
|
Total revenues
|
524
|
|
|
111
|
|
|
(23
|
)
|
|
612
|
|
||||
|
Income from equity method investments
|
—
|
|
|
14
|
|
|
—
|
|
|
14
|
|
||||
|
Net gain (loss) on disposal of assets and other income
|
1
|
|
|
6
|
|
|
(63
|
)
|
(d)
|
(56
|
)
|
||||
|
Less:
|
|
|
|
|
|
|
|
||||||||
|
Production expenses
|
134
|
|
|
53
|
|
|
—
|
|
|
187
|
|
||||
|
Marketing costs
|
32
|
|
|
14
|
|
|
—
|
|
|
46
|
|
||||
|
Exploration expenses
|
18
|
|
|
6
|
|
|
—
|
|
|
24
|
|
||||
|
Depreciation, depletion and amortization
|
487
|
|
|
50
|
|
|
12
|
|
|
549
|
|
||||
|
Impairments
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||
|
Other expenses
(a)
|
118
|
|
|
16
|
|
|
120
|
|
(e)
|
254
|
|
||||
|
Taxes other than income
|
42
|
|
|
—
|
|
|
1
|
|
|
43
|
|
||||
|
Net interest and other
|
—
|
|
|
—
|
|
|
79
|
|
|
79
|
|
||||
|
Income tax provision (benefit)
|
(112
|
)
|
|
(12
|
)
|
|
(129
|
)
|
|
(253
|
)
|
||||
|
Segment income (loss) / Income (loss) from continuing operations
|
$
|
(195
|
)
|
|
$
|
4
|
|
|
$
|
(169
|
)
|
|
$
|
(360
|
)
|
|
Capital expenditures
(b)
|
$
|
315
|
|
|
$
|
32
|
|
|
$
|
3
|
|
|
$
|
350
|
|
|
(a)
|
Includes other operating expenses and general and administrative expenses.
|
|
(b)
|
Includes accruals.
|
|
(c)
|
Unrealized loss on commodity derivative instruments.
|
|
(d)
|
Related to the net loss on disposal of assets. See Note
6
.
|
(e)
Includes pension settlement loss of
$48 million
and severance related expenses associated with workforce reductions of
$7 million
. See Note
8
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8
. Defined Benefit Postretirement Plans
The following summarizes the components of net periodic benefit cost:
|
|
Three Months Ended March 31,
|
||||||||||||||
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||
|
(In millions)
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||
|
Service cost
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
Interest cost
|
8
|
|
|
11
|
|
|
2
|
|
|
3
|
|
||||
|
Expected return on plan assets
|
(12
|
)
|
|
(15
|
)
|
|
—
|
|
|
—
|
|
||||
|
Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
– prior service cost (credit)
|
(2
|
)
|
|
(2
|
)
|
|
(2
|
)
|
|
(1
|
)
|
||||
|
– actuarial loss
|
2
|
|
|
3
|
|
|
—
|
|
|
—
|
|
||||
|
Net settlement loss
(a)
|
14
|
|
|
48
|
|
|
—
|
|
|
—
|
|
||||
|
Net periodic benefit cost
|
$
|
16
|
|
|
$
|
51
|
|
|
$
|
1
|
|
|
$
|
3
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan’s total service and interest cost for that year.
|
12
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
During the
first three months of 2017
, we recorded the effects of settlements of our U.S. pension plans. As required, we remeasured the plans’ assets and liabilities as of the applicable balance sheet dates. The cumulative effects of these events are included in the remeasurement and reflected in both the pension liability and net periodic benefit cost.
During the
first three months of 2017
, we made contributions of
$13 million
to our funded pension plans and we expect to make additional contributions up to an estimated
$47 million
over the remainder of
2017
. During the
first three months of 2017
, we made payments of
$7 million
and
$6 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
. For the three-month periods in 2017 and 2016, our effective income tax rates on continuing operations was as follows:
|
|
|
Three Months Ended March 31,
|
||||||
|
(In millions)
|
|
2017
|
|
2016
|
||||
|
Total pre-tax income (loss) from continuing operations
|
|
$
|
(16
|
)
|
|
$
|
(613
|
)
|
|
Total income tax expense (benefit)
|
|
$
|
34
|
|
|
$
|
(253
|
)
|
|
Effective income tax expense (benefit) rate on continuing operations
|
|
213
|
%
|
|
(41
|
)%
|
||
|
|
|
|
|
|
||||
|
Income taxes at the statutory tax rate of 35%
|
|
$
|
(6
|
)
|
|
$
|
(214
|
)
|
|
Effects of foreign operations
|
|
(4
|
)
|
|
(34
|
)
|
||
|
Adjustments to valuation allowances
|
|
57
|
|
|
—
|
|
||
|
State income taxes
|
|
(13
|
)
|
|
(6
|
)
|
||
|
Other federal tax effects
|
|
—
|
|
|
1
|
|
||
|
Effective income tax expense (benefit) on continuing operations
|
|
$
|
34
|
|
|
$
|
(253
|
)
|
The rate change between years for the first quarter was driven by our assessment of the realizability of federal deferred tax assets being generated in the quarter, the impact of foreign operations, and the settlement of our 2011-2013 Alaska audit.
We expect to be in a cumulative loss position in 2017, for tax purposes, and as a result have placed a full valuation allowance on our federal deferred tax assets for the quarter totaling
$57 million
. During 2017 we expect to realize no tax benefit on any federal deferred tax assets generated. See Deferred Tax Assets section below for further detail.
In the first quarter, we also settled our 2011-2013 Alaska income tax audit. The settlement of the audit resulted in the recognition of a tax benefit totaling
$13 million
.
The impact of foreign operations for the quarter was primarily related to a tax benefit on currency remeasurement impacts totaling
$3 million
. The foreign tax expense impacts related to our Libya, E.G. and U.K. operations in the first quarter of 2017 are largely offset by deferred tax benefits being generated in the U.K. associated with tax refunds related to future decommissioning costs. In Libya, reliable estimates of 2017 and 2016 annual ordinary income from our Libyan 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 impacts applicable to Libyan ordinary income (loss) was recorded as a discrete item in the first three months of 2017 and 2016. For the first three months of 2017 and 2016, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss). Excluding Libya, the effective income tax expense (benefit) rates would be
(16)%
and
(40)%
for the
first three months of 2017
and 2016.
13
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
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. The estimated realizability of the benefit of our deferred tax asset is assessed considering a preponderance of evidence. This assessment requires analysis of all available positive and negative evidence. Positive evidence includes reversals of temporary differences, forecasts of future taxable income, assessment of future business assumptions and applicable tax planning strategies. Negative evidence includes losses in recent years as well as the forecasts of future income (loss) in the realizable period. We expected to be in a cumulative loss position in 2017, which constitutes significant objective negative evidence as to the future realizability of the value of our federal deferred tax assets. Due to this negative evidence, we placed a full valuation allowance on our federal deferred tax assets during 2016 and expect to realize no tax benefit on any federal deferred tax assets generated in 2017.
10
. Inventories
Crude oil and natural gas are recorded at weighted average cost and carried at the lower of cost or net realizable value. Supplies and other items consist principally of tubular goods and equipment which are valued at weighted average cost and reviewed periodically for obsolescence or impairment when market conditions indicate.
|
|
March 31,
|
|
December 31,
|
||||
|
(In millions)
|
2017
|
|
2016
|
||||
|
Crude oil and natural gas
|
$
|
6
|
|
|
$
|
6
|
|
|
Supplies and other items
|
139
|
|
|
130
|
|
||
|
Inventories
|
$
|
145
|
|
|
$
|
136
|
|
11
. Property, Plant and Equipment, net of Accumulated Depreciation, Depletion and Amortization
|
|
March 31,
|
|
December 31,
|
||||
|
(In millions)
|
2017
|
|
2016
|
||||
|
North America E&P
|
$
|
14,025
|
|
|
$
|
14,158
|
|
|
International E&P
|
2,419
|
|
|
2,470
|
|
||
|
Corporate
|
89
|
|
|
99
|
|
||
|
Net property, plant and equipment
|
$
|
16,533
|
|
|
$
|
16,727
|
|
Our Libya operations have been interrupted in recent years due to civil unrest. On September 14, 2016, Force Majeure was lifted and production resumed in October 2016 at our Waha concession. During December 2016, liftings resumed from the Es Sider crude oil terminal. Sales volumes and production continued during the first quarter of 2017, except for a brief interruption in March 2017 due to civil unrest.
As of
March 31, 2017
, our net property, plant and equipment investment in Libya is
$767 million
, and total proved reserves (unaudited) in Libya as of December 31, 2016 are
206 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
$767 million
by a significant amount.
Exploratory well costs capitalized greater than one year after completion of drilling was
$118 million
as of both
March 31, 2017
and
December 31, 2016
. In April 2017, we received host government approval to develop Block D offshore E.G. through unitization with the Alba field. As such, the
$22 million
exploratory well costs capitalized greater than one year after completion associated with the Corona well will begin depreciation during the second quarter of 2017.
14
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
12
. Impairments and Exploration Expenses
The following table summarizes impairment charges of proved properties:
|
|
Three Months Ended March 31,
|
||||||
|
(in millions)
|
2017
|
|
2016
|
||||
|
Total impairments
|
$
|
4
|
|
|
$
|
1
|
|
2017
- As a result of our announced disposition of our Canadian business in the first quarter of 2017, we recorded a pre-tax non-cash impairment charge of
$6.6 billion
primarily related to property, plant and equipment. This impairment in our Canadian business is reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for all periods presented. See Note 6 for relevant detail regarding dispositions.
The following table summarizes the components of exploration expenses:
|
|
Three Months Ended March 31,
|
||||||
|
(In millions)
|
2017
|
|
2016
|
||||
|
Exploration Expenses
|
|
|
|
||||
|
Unproved property impairments
|
$
|
20
|
|
|
$
|
11
|
|
|
Geological and geophysical
|
1
|
|
|
—
|
|
||
|
Other
|
7
|
|
|
13
|
|
||
|
Total exploration expenses
|
$
|
28
|
|
|
$
|
24
|
|
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
March 31, 2017
and
December 31, 2016
by fair value hierarchy level.
|
|
March 31, 2017
|
||||||||||||||
|
(In millions)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
Derivative instruments, assets
|
|
|
|
|
|
|
|
||||||||
|
Commodity (a)
|
$
|
—
|
|
|
$
|
19
|
|
|
$
|
—
|
|
|
$
|
19
|
|
|
Interest rate
|
—
|
|
|
67
|
|
|
—
|
|
|
67
|
|
||||
|
Derivative instruments, assets
|
$
|
—
|
|
|
$
|
86
|
|
|
$
|
—
|
|
|
$
|
86
|
|
|
Derivative instruments, liabilities
|
|
|
|
|
|
|
|
||||||||
|
Commodity (a)
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
2
|
|
|
Derivative instruments, liabilities
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
2
|
|
|
(a)
|
Derivative instruments are recorded on a net basis in our balance sheet. See Note
14
.
|
|
|
December 31, 2016
|
||||||||||||||
|
(In millions)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
Derivative instruments, assets
|
|
|
|
|
|
|
|
||||||||
|
Commodity (a)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Interest rate
|
—
|
|
|
68
|
|
|
—
|
|
|
68
|
|
||||
|
Derivative instruments, assets
|
$
|
—
|
|
|
$
|
68
|
|
|
$
|
—
|
|
|
$
|
68
|
|
|
Derivative instruments, liabilities
|
|
|
|
|
|
|
|
||||||||
|
Commodity (a)
|
$
|
—
|
|
|
$
|
60
|
|
|
$
|
—
|
|
|
$
|
60
|
|
|
Derivative instruments, liabilities
|
$
|
—
|
|
|
$
|
60
|
|
|
$
|
—
|
|
|
$
|
60
|
|
|
(a)
|
Derivative instruments are recorded on a net basis in our balance sheet. See Note
14
.
|
15
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
Commodity derivatives include three-way collars, call options and swaps. These instruments are measured at fair value using either a Black-Scholes or a modified Black-Scholes Model. Inputs to the models include commodity prices, interest rates, and implied volatility and are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.
Both our interest rate swaps and forward starting 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- 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.
|
|
|
|
|
|
|
|
|
As a result of our announced disposition of our Canadian business in the first quarter of 2017, we recorded a non-cash impairment charge of
$6.6 billion
primarily related to property, plant and equipment. This impairment was recorded for excess net book value over anticipated sales proceeds less costs to sell. Fair values of assets held for sale were determined based upon the anticipated sales proceeds less costs to sell, which resulted in a Level 2 classification. See Note
6
for relevant detail regarding dispositions.
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
March 31, 2017
and
December 31, 2016
.
|
|
March 31, 2017
|
|
December 31, 2016
|
||||||||||||
|
|
Fair
|
|
Carrying
|
|
Fair
|
|
Carrying
|
||||||||
|
(In millions)
|
Value
|
|
Amount
|
|
Value
|
|
Amount
|
||||||||
|
Financial assets
|
|
|
|
|
|
|
|
||||||||
|
Other current assets
|
$
|
10
|
|
|
$
|
10
|
|
|
$
|
7
|
|
|
$
|
7
|
|
|
Other noncurrent assets
|
284
|
|
|
287
|
|
|
105
|
|
|
108
|
|
||||
|
Total financial assets
|
$
|
294
|
|
|
$
|
297
|
|
|
$
|
112
|
|
|
$
|
115
|
|
|
Financial liabilities
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Other current liabilities
|
$
|
64
|
|
|
$
|
75
|
|
|
$
|
68
|
|
|
$
|
75
|
|
|
Long-term debt, including current portion (a)
|
7,535
|
|
|
7,293
|
|
|
7,449
|
|
|
7,292
|
|
||||
|
Deferred credits and other liabilities
|
112
|
|
|
106
|
|
|
114
|
|
|
107
|
|
||||
|
Total financial liabilities
|
$
|
7,711
|
|
|
$
|
7,474
|
|
|
$
|
7,631
|
|
|
$
|
7,474
|
|
(a)
Excludes capital leases, debt issuance costs and interest rate swap adjustments.
Fair values of our financial assets included in other noncurrent assets, and of our financial liabilities included in other current liabilities and deferred credits and other liabilities, are measured using an income approach and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value.
16
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
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.
|
|
March 31, 2017
|
|
|
||||||||||
|
(In millions)
|
Asset
|
|
Liability
|
|
Net Asset
|
|
Balance Sheet Location
|
||||||
|
Fair Value Hedges
|
|
|
|
|
|
|
|
||||||
|
Interest rate
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
2
|
|
|
Other current assets
|
|
Cash Flow Hedges
|
|
|
|
|
|
|
|
||||||
|
Interest rate
|
$
|
65
|
|
|
$
|
—
|
|
|
$
|
65
|
|
|
Other current assets
|
|
Total Designated Hedges
|
$
|
67
|
|
|
$
|
—
|
|
|
$
|
67
|
|
|
|
|
Not Designated as Hedges
|
|
|
|
|
|
|
|
||||||
|
Commodity
|
$
|
16
|
|
|
$
|
—
|
|
|
$
|
16
|
|
|
Other current assets
|
|
Commodity
|
3
|
|
|
2
|
|
|
1
|
|
|
Other noncurrent assets
|
|||
|
Total Not Designated as Hedges
|
$
|
19
|
|
|
$
|
2
|
|
|
$
|
17
|
|
|
|
|
Total
|
$
|
86
|
|
|
$
|
2
|
|
|
$
|
84
|
|
|
|
|
|
December 31, 2016
|
|
|
||||||||||
|
(In millions)
|
Asset
|
|
Liability
|
|
Net Asset
|
|
Balance Sheet Location
|
||||||
|
Fair Value Hedges
|
|
|
|
|
|
|
|
||||||
|
Interest rate
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
3
|
|
|
Other current assets
|
|
Interest rate
|
1
|
|
|
—
|
|
|
1
|
|
|
Other noncurrent assets
|
|||
|
Cash Flow Hedges
|
|
|
|
|
|
|
|
||||||
|
Interest rate
|
$
|
64
|
|
|
$
|
—
|
|
|
$
|
64
|
|
|
Other noncurrent assets
|
|
Total Designated Hedges
|
$
|
68
|
|
|
$
|
—
|
|
|
$
|
68
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Not Designated as Hedges
|
|
|
|
|
|
|
|
||||||
|
Commodity
|
$
|
—
|
|
|
$
|
60
|
|
|
$
|
(60
|
)
|
|
Other current liabilities
|
|
Total Not Designated as Hedges
|
$
|
—
|
|
|
$
|
60
|
|
|
$
|
(60
|
)
|
|
|
|
Total
|
$
|
68
|
|
|
$
|
60
|
|
|
$
|
8
|
|
|
|
Derivatives Designated as Fair Value Hedges
The following table presents, by maturity date, information about our interest rate swap agreements, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.
|
|
March 31, 2017
|
|
December 31, 2016
|
||||||||
|
|
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
|
|
5.27
|
%
|
|
$
|
600
|
|
5.10
|
%
|
|
March 15, 2018
|
$
|
300
|
|
5.24
|
%
|
|
$
|
300
|
|
5.04
|
%
|
17
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 has a gross impact that is not material to net interest and other in all periods presented. Additionally, there is no ineffectiveness related to fair value hedges in all periods presented.
Derivatives Designated as Cash Flow Hedges
During the third quarter of 2016, we entered into forward starting interest rate swaps to hedge the variations in cash flows related to fluctuations in long term interest rates from debt that is probable to be refinanced by us in 2018, specifically interest rate risk associated with future changes in the benchmark treasury rate. The occurrence of the forecasted transaction is probable and each respective derivative contract can be tied to an anticipated underlying dollar notional amount. At conclusion of the hedge in the first quarter of 2018, the final value will be reclassified from accumulated other comprehensive income into earnings. At
March 31, 2017
, the forward starting interest rate swaps continued to qualify as an effective hedge and the ineffective portion was not significant in the quarter.
The following table presents, by maturity date, information about our forward starting interest rate swap agreements, including the rate.
|
|
|
March 31, 2017
|
||
|
|
|
Aggregate Notional Amount
|
|
Weighted Average, LIBOR
|
|
Maturity Dates
|
|
(in millions)
|
|
Fixed Rate
|
|
March 15, 2018
|
|
$750
|
|
1.57%
|
The following table sets forth the net impact of the derivatives designated as cash flow hedges on other comprehensive income (loss).
|
|
Three Months Ended March 31,
|
||||||
|
(In millions)
|
2017
|
|
2016
|
||||
|
Cash Flow Hedges
|
|
|
|
||||
|
Beginning balance
|
$
|
60
|
|
|
$
|
—
|
|
|
Change in fair value recognized in other comprehensive income
|
1
|
|
|
—
|
|
||
|
Reclassification from other comprehensive income
|
—
|
|
|
—
|
|
||
|
Ending balance
|
$
|
61
|
|
|
$
|
—
|
|
At
March 31, 2017
, accumulated other comprehensive income included deferred gains of
$61 million
related to interest rate cash flow hedges. We expect to reclassify this amount into earnings as an adjustment to net interest and other at the conclusion of the hedge in the first quarter of 2018.
18
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
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 2018. These commodity derivatives consist of three-way collars, swaps, and call options. Three-way collars consist of a sold call (ceiling), a purchased put (floor) and a sold put. The ceiling price is the maximum we will receive for the contract volumes, the floor is the minimum price we will receive, unless the market price falls below the sold put strike price. In this case, we receive the NYMEX WTI/Henry Hub price plus the difference between the floor and the sold put price. These commodity derivatives were not designated as hedges. The following table sets forth outstanding derivative contracts as of
March 31, 2017
and the weighted average prices for those contracts:
|
(a)
|
Call options settle monthly.
|
|
(a)
|
Subsequent to March 31, 2017, we entered into
70,000
MMBTU/day of three-way collars for January - December 2018 with a ceiling price of
$3.62
, a floor price of
$3.00
, and a sold put price of
$2.50
and
40,000
MMBTU/day of three-way collars for January - March 2018 with a ceiling price of
$4.47
, a floor price of
$3.40
, and a sold put price of
$2.75
.
|
The mark-to-market impact and settlement of these commodity derivative instruments appears in sales and other operating revenues in our consolidated statements of income for the three month period ended
March 31, 2017
and 2016, respectively. The first quarter 2017 impact was a net gain of $
81 million
compared to a net loss of
$2 million
for the same respective period in 2016. Net settlements of commodity derivative instruments for the three month period ended
March 31, 2017
was
$4 million
compared to $
22 million
for the respective period in 2016.
19
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
15
. Incentive Based Compensation
Stock options, restricted stock awards and restricted stock units
The following table presents a summary of activity for the
first three months
of
2017
:
|
|
Stock Options
|
|
Restricted Stock Awards & Units
|
||||||||||
|
|
Number of
Shares
|
|
Weighted
Average
Exercise Price
|
|
Awards
|
|
Weighted
Average Grant
Date Fair Value
|
||||||
|
Outstanding at December 31, 2016
|
11,915,533
|
|
|
|
$27.71
|
|
|
6,933,533
|
|
|
|
$14.44
|
|
|
Granted
|
694,142
|
|
(a)
|
|
$15.87
|
|
|
3,787,316
|
|
|
|
$16.39
|
|
|
Options Exercised/Stock Vested
|
—
|
|
|
—
|
|
|
(1,447,787
|
)
|
|
|
$9.57
|
|
|
|
Canceled
|
(500,612
|
)
|
|
|
$29.18
|
|
|
(156,244
|
)
|
|
|
$16.57
|
|
|
Outstanding at March 31, 2017
|
12,109,063
|
|
|
|
$26.97
|
|
|
9,116,818
|
|
|
|
$15.99
|
|
(a)
The weighted average grant date fair value of stock option awards granted was
$6.10
per share.
Stock-based performance unit awards
During the
first three months
of
2017
, we granted
563,631
stock-based performance units to certain officers. The grant date fair value per unit was
$17.75
.
16
. Debt
Revolving Credit Facility
As of
March 31, 2017
, we had no borrowings against our
$3.3 billion
revolving credit facility (the “Credit Facility”), as described below.
As of March 31, 2017 we had long-term debt due within one year of $
1.5 billion
. This includes
$682 million
of
6.0%
senior unsecured notes due in the fourth quarter of 2017 and
$854 million
of
5.9%
senior unsecured notes due in the first quarter of 2018.
The Credit Facility includes a covenant requiring that our ratio of total debt to total capitalization not exceed
65%
as of the last day of each fiscal quarter. If an event of default occurs, the lenders holding more than half of the commitments may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility. As of
March 31, 2017
, we were in compliance with this covenant with a debt-to-capitalization ratio of
37%
.
17
. Reclassifications Out of Accumulated Other Comprehensive Loss
The following table presents a summary of amounts reclassified from accumulated other comprehensive loss:
20
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
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
|
|
Three Months Ended March 31,
|
||||||
|
(In millions)
|
2017
|
|
2016
|
||||
|
Net cash (used in) operating activities:
|
|
|
|
||||
|
Interest paid (net of amounts capitalized)
|
$
|
(64
|
)
|
|
$
|
(55
|
)
|
|
Income taxes paid to taxing authorities
|
(15
|
)
|
|
(15
|
)
|
||
|
Noncash investing activities, related to continuing operations:
|
|
|
|
|
|
||
|
Asset retirement cost increase
|
$
|
4
|
|
|
$
|
2
|
|
|
Asset retirement obligations assumed by buyer
|
—
|
|
|
54
|
|
||
|
Increase in capital expenditure accrual
|
76
|
|
|
—
|
|
||
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
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 exploration and production company based in Houston, Texas focused on U.S. unconventional resource plays with operations in North America, Africa and Europe. Total proved reserves were 1.4 billion boe at December 31, 2016, excluding our Canadian business, and total assets were
$25 billion
at
March 31, 2017
.
As discussed in Note 6 to the consolidated financial statements, we entered into an agreement for the sale of our Canadian business, which has been reflected as discontinued operations and is excluded from operations in all periods presented. Assets and liabilities of this business are presented as held for sale in the consolidated balance sheets as of March 31, 2017 and December 31, 2016.
Execution on our strategic actions and financial results include the following:
Simplifying and concentrating portfolio
|
•
|
Entered into an agreement for the sale of our Canadian business to Shell and Canadian Natural Resources Limited for
$2.5 billion
, excluding closing adjustments
|
|
•
|
Announced acquisitions of approximately
91,000
net acres in the Permian basin for
$1.8 billion
, excluding closing adjustments, to be funded with cash on hand
|
Relentless focus on costs
|
•
|
North America E&P production expenses rate decreased 6% to $5.79 per boe and production cost are down nearly 20% compared to the same quarter of last year
|
|
•
|
Eagle Ford's average completed well costs were $4 million in the first quarter of 2017 compared to $4.3 million in the same quarter of last year
|
Operational updates
|
•
|
Net sales volumes from continuing operations are 334 mboed which is flat versus the same quarter last year, this includes 208 mboed sales volumes in our North America E&P segment
|
|
•
|
Ended the first quarter of 2017 with 20 rigs operating in the U.S. resource plays, an increase of over 100% compared to the first quarter of 2016
|
|
•
|
First Company-operated STACK Meramec black oil spacing pilot online and performing in line with expectations
|
|
•
|
Our Eagle Ford wells were drilled at an average rate of 2,500 feet per day during the quarter with one of our wells setting a new Company-record at more than 4,000 feet per day
|
22
Financial results
|
•
|
Ended the first quarter of 2017 with
$2.5 billion
of cash on hand
|
|
•
|
Cash provided by operating activities from continuing operations of $
501 million
for the first
three months
of 2017, primarily driven by our average crude oil and condensate price realizations of
$48.93
per bbl
|
|
•
|
Improving our net loss per share from continuing operations to
$0.06
in the
first quarter
of
2017
as compared to a net loss per share from continuing operations of
$0.49
in the same period last year
|
|
◦
|
Included in the
first quarter
2017 net loss is an increase in sales and other operating revenues of approximately 70% to
$954 million
while seeing a reduction in production and other operating expenses of 17%
|
|
◦
|
Commodity derivative instruments generated a mark-to-market net gain of $
81 million
in the first quarter of 2017
|
|
•
|
Incurred a
$4.9 billion
after-tax net loss on our discontinued operations primarily as a result of a non-cash impairment charge during the first quarter of 2017
|
Operations
The following table presents a summary of our sales volumes for each of our segments. Refer to the following Results of Operations section for a price-volume analysis for each of the segments.
North America E&P
Net sales volumes in the segment were lower in the first quarter of 2017 primarily as a result of a reduction of 22 mboed mainly consisting of the disposition of Wyoming and certain non-operated assets in West Texas and New Mexico in 2016. The following tables provide details regarding net sales volumes, sales mix and operational drilling activity for our significant operations within this segment:
|
|
Three Months Ended March 31,
|
||||
|
Net Sales Volumes
|
2017
|
|
2016
|
|
Increase (Decrease)
|
|
Equivalent Barrels
(mboed)
|
|
|
|
|
|
|
Oklahoma Resource Basins
|
44
|
|
27
|
|
63%
|
|
Eagle Ford
|
99
|
|
121
|
|
(18)%
|
|
Bakken
|
48
|
|
57
|
|
(16)%
|
|
Other North America
(a)
|
17
|
|
34
|
|
(50)%
|
|
Total North America E&P
|
208
|
|
239
|
|
(13)%
|
|
|
|
Three Months Ended March 31, 2017
|
||||||
|
Sales Mix - U.S. Resource Plays
|
|
Oklahoma Resource Basins
|
|
Eagle Ford
|
|
Bakken
|
|
Total
|
|
Crude oil and condensate
|
|
27%
|
|
60%
|
|
82%
|
|
58%
|
|
Natural gas liquids
|
|
30%
|
|
20%
|
|
10%
|
|
20%
|
|
Natural gas
|
|
43%
|
|
20%
|
|
8%
|
|
22%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23
|
|
Three Months Ended March 31,
|
||
|
|
2017
|
|
2016
|
|
Gross Operated
|
|
|
|
|
|
|
|
|
|
Oklahoma Resource Basins:
|
|
|
|
|
Wells drilled to total depth
|
15
|
|
5
|
|
Wells brought to sales
|
12
|
|
3
|
|
Eagle Ford:
|
|
|
|
|
Wells drilled to total depth
|
45
|
|
58
|
|
Wells brought to sales
|
47
|
|
50
|
|
Bakken:
|
|
|
|
|
Wells drilled to total depth
|
12
|
|
3
|
|
Wells brought to sales
|
4
|
|
6
|
|
•
|
Oklahoma Resource Basins
– Of the 12 gross operated wells brought to sales in the first quarter of 2017, 11 were in the STACK Meramec and one well was in the SCOOP Woodford. The SCOOP Woodford well that was brought to sales was an extended lateral.
|
Of the 12 gross operated wells brought to sales in the first quarter of 2017, five were part of our first operated STACK infill spacing test, the Yost pilot, and the others were focused primarily on STACK lease retention and delineation. The Yost pilot, located in the normally pressured black oil window in central Kingfisher County, successfully tested 107-acre well spacing with completions of approximately 2,500 pounds of proppant per lateral foot during the first quarter of 2017. Rig activity increased from five to seven drilling rigs in the STACK/SCOOP during the first quarter of 2017. We expect to average approximately 10 drilling rigs in 2017.
|
•
|
Eagle Ford
– During the first quarter of 2017, we brought 47 gross operated wells to sales, of which
33
were Lower Eagle Ford,
12
were Upper Eagle Ford and
2
were Austin Chalk. We held our activity levels flat from year end 2016 with six rigs drilling in Karnes, Atascosa, Live Oak and Gonzales counties.
|
During the quarter, wells were drilled at an average rate of 2,500 feet per day and one of our wells achieved a new Company-record at more than 4,000 feet per day. We ended the quarter with six drilling rigs and expect to maintain an average of six drilling rigs in 2017.
|
•
|
Bakken
– Of the four gross operated wells brought to sales in East Myrmidon during the first quarter of 2017, three were in the Three Forks formation and one in the Middle Bakken formation. In the first quarter we increased our rig activity from one to seven drilling rigs, and expect to average approximately six drilling rigs in 2017.
|
|
•
|
Other North America
– Net sales volumes declined in the
first quarter
of 2017 primarily due to the disposition of Wyoming and certain non-operated assets in West Texas and New Mexico in 2016. See Note
6
to the consolidated financial statements for information about dispositions. This decrease was partially offset by the Gunflint field located in Mississippi Canyon block 948 in the Gulf of Mexico which began production in the second half of 2016.
|
24
International E&P
Net sales volumes in the segment were higher in the
first quarter
of
2017
compared to the first quarter of 2016 due primarily to the completion and start-up of our E.G. Alba field compression project in mid-2016 and planned maintenance activities which occurred during the first quarter of 2016. The following table provides details regarding net sales volumes for our significant operations within this segment.
|
|
Three Months Ended March 31,
|
||||
|
Net Sales Volumes
|
2017
|
|
2016
|
|
Increase (Decrease)
|
|
Equivalent Barrels
(mboed)
|
|
|
|
|
|
|
Equatorial Guinea
|
103
|
|
84
|
|
23%
|
|
United Kingdom
(a)
|
11
|
|
12
|
|
(8)%
|
|
Libya
|
12
|
|
—
|
|
100%
|
|
Total International E&P
|
126
|
|
96
|
|
31%
|
|
Equity Method Investees
|
|
|
|
|
|
|
LNG
(mtd)
|
6,147
|
|
4,322
|
|
42%
|
|
Methanol
(mtd)
|
1,307
|
|
1,280
|
|
2%
|
|
Condensate & LPG
(boed)
|
14,546
|
|
10,208
|
|
42%
|
|
(a)
|
Includes natural gas acquired for injection and subsequent resale of
7
mmcfd and
5
mmcfd for the
first quarter
s of
2017
and
2016
.
|
|
•
|
Equatorial Guinea
–
First quarter
2017 net sales were higher compared to the same quarter in 2016 as a result of the completion and start-up of our Alba field compression project in mid-2016 and planned maintenance activities which occurred during the first quarter of 2016. In April 2017, we received host government approval to develop Block D offshore E.G. through unitization with the Alba field.
|
|
•
|
United Kingdom
– Net sales volumes in the first
three months
of 2017 were marginally lower compared to the first quarter of 2016 as a result of reliability issues at the outside-operated Foinaven Field.
|
|
•
|
Libya
– Our Libya operations have been interrupted in recent years due to civil unrest. In late 2016, liftings resumed from the Es Sider crude oil terminal. Sales volumes and production continued during the first quarter of 2017, except for a brief interruption in March 2017 due to civil unrest.
|
Discontinued Operations - Oil Sands Mining
In March 2017, we entered into an agreement to sell our Canadian business, including our OSM segment, to Shell and Canadian Natural Resources Limited for $2.5 billion in cash, excluding closing adjustments. We expect to close the sale in mid-2017 with an effective date of January 1, 2017.
The oil sands mining business is excluded from the segment results and is reported as discontinued operations for all periods presented. Our net synthetic crude oil sales volumes were
60
mbbld in the
first quarter of
2017
compared to
59
mbbld in the same periods of
2016
. We hold a 20% non-operated working interest in the Athabasca Oil Sands Project.
Market Conditions
Crude oil, natural gas and NGL benchmarks increased in the
first quarter of
2017
as compared to the same period in
2016
; as a result, we experienced increased price realizations associated with those benchmarks. As 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.
25
North America E&P
The following table presents our average price realizations and the related benchmarks for crude oil, NGLs and natural gas for the
first quarter of
2017
and
2016
.
|
|
Three Months Ended March 31,
|
||||
|
|
2017
|
|
2016
|
|
Increase
|
|
Average Price Realizations
(a)
|
|
|
|
|
|
|
Crude Oil and Condensate
(per bbl)
(b)
|
$48.46
|
|
$28.21
|
|
72%
|
|
Natural Gas Liquids
(per bbl)
|
19.33
|
|
8.12
|
|
138%
|
|
Total Liquid Hydrocarbons
(per bbl)
|
41.13
|
|
24.00
|
|
71%
|
|
Natural Gas
(per mcf)
(c)
|
3.02
|
|
2.02
|
|
50%
|
|
Benchmarks
|
|
|
|
|
|
|
WTI crude oil
(per bbl)
|
$51.78
|
|
$33.63
|
|
54%
|
|
LLS crude oil
(per bbl)
|
53.39
|
|
35.33
|
|
51%
|
|
Mont Belvieu NGLs
(per bbl)
(d)
|
22.93
|
|
13.95
|
|
64%
|
|
Henry Hub natural gas
(per mmbtu)
|
3.32
|
|
2.09
|
|
59%
|
|
(a)
|
Excludes gains or losses on commodity derivative instruments.
|
|
(b)
|
Inclusion of realized gains on crude oil derivative instruments would have increased liquid hydrocarbons average price realizations by
$0.34
per bbl and
$1.64
per bbl for the
first quarter
2017
and
2016
.
|
|
(c)
|
Inclusion of realized gains (losses) on natural gas derivative instruments would have a minimal impact on average price realizations for the periods presented.
|
|
(d)
|
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 for the
first quarter of
2017
and
2016
.
|
(a)
|
Average of monthly prices obtained from EIA website.
|
Our U.K. liquid hydrocarbon production is generally sold in relation to the Brent crude benchmark. Our production from the Alba field in E.G. is condensate and gas. Condensate is sold at market prices. The Alba Plant extracts NGLs and secondary condensate from gas, leaving dry natural gas. The processed NGLs are sold by Alba Plant at market prices, with our share of its income/loss reflected in Income from equity method investments. The dry natural gas from Alba Plant is supplied to AMPCO and EGHoldings under long-term contracts at fixed prices; therefore, our reported average realized prices for NGLs and natural gas will not fully track market price movements. Because of the location and limited local demand for natural gas in E.G., we consider the prices under the contracts with Alba Plant LLC, EGHoldings and AMPCO to be comparable to the price that could be realized from transactions with unrelated parties in this market under the same or similar circumstances. EGHoldings and AMPCO process the gas into LNG and methanol, which are sold at market prices, with our share of their income/loss reflected in the Income from equity method investments line item on the Consolidated Statements of Income. Although uncommon, any dry gas not sold is returned offshore and re-injected into the Alba field for later production.
26
Results of Operations
Three Months Ended March 31, 2017
vs.
Three Months Ended March 31, 2016
Sales and other operating revenues, including related party
are presented by segment in the table below:
|
|
Three Months Ended March 31,
|
||||||
|
(In millions)
|
2017
|
|
2016
|
||||
|
Sales and other operating revenues, including related party
|
|
|
|
||||
|
North America E&P
|
$
|
674
|
|
|
$
|
493
|
|
|
International E&P
|
203
|
|
|
96
|
|
||
|
Segment sales and other operating revenues, including related party
|
$
|
877
|
|
|
$
|
589
|
|
|
Unrealized gain (loss) on commodity derivative instruments
|
77
|
|
|
(23
|
)
|
||
|
Sales and other operating revenues, including related party
|
$
|
954
|
|
|
$
|
566
|
|
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 March 31, 2017 includes a net sales volume reduction of
22
mboed primarily consisting of the disposition of Wyoming and certain non-operated assets in West Texas and New Mexico in 2016.
|
Marketing revenues
decreased
$12 million
in the first quarter of 2017 from the comparable 2016 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 decrease is primarily related to lower marketed volumes in North America.
Income from equity method investments
increased
$
55 million
in the
first quarter of 2017
from the comparable
2016
period. The improvement is due to an increase in net sales volumes primarily driven by the completion of the Alba field compression project in E.G. during the second half of 2016. Also contributing to the increase was higher price realizations from LPG at our Alba plant and methanol at our AMPCO methanol facility.
Net gain (loss) on disposal of assets
increased
$61 million
in the
first quarter of 2017
related to the sale of non-core assets in the first quarter of 2016 in the Gulf of Mexico.
Production expenses
decreased
$36 million
in the first quarter of 2017 versus the same period in 2016. North America E&P declined $25 million primarily due to the disposition of our non-core assets in Wyoming during the second half of 2016. International E&P declined $11 million primarily as a result of lower planned maintenance costs in the first quarter of 2017 in E.G. and U.K. Additionally, contributing to the U.K. decrease was a more favorable exchange rate on expenses.
27
The
first quarter
of
2017
production expense rate (expense per boe) for North America E&P declined as cost reductions, due to the commodity price environment, occurred at a rate faster than our production declined. The expense rate for International E&P declined due to an increase in volumes, combined with reduced maintenance and project costs in the E.G. and U.K.
The following table provides production expense rates for each segment:
|
|
Three Months Ended March 31,
|
||||||
|
($ per boe)
|
2017
|
|
2016
|
||||
|
Production Expense Rate
|
|
|
|
||||
|
North America E&P
|
|
$5.79
|
|
|
|
$6.17
|
|
|
International E&P
|
|
$3.72
|
|
|
|
$6.08
|
|
Exploration expenses
includes unproved property impairments, dry well costs, geological and geophysical, and other which
increased
$4 million
in the first quarter of 2017. Unproved property impairments increased primarily as a result of more lease expirations and our decision to not drill certain leases in Eagle Ford and Oklahoma. The following table summarizes the components of exploration expenses:
|
|
Three Months Ended March 31,
|
||||||
|
(In millions)
|
2017
|
|
2016
|
||||
|
Exploration Expenses
|
|
|
|
||||
|
Unproved property impairments
|
$
|
20
|
|
|
$
|
11
|
|
|
Geological and geophysical
|
1
|
|
|
—
|
|
||
|
Other
|
7
|
|
|
13
|
|
||
|
Total exploration expenses
|
$
|
28
|
|
|
$
|
24
|
|
Depreciation, depletion and amortization
increased
$7 million
primarily as a result of an increase of $25 million in International E&P due to increased sales volumes in E.G. and increased U.K. asset retirement costs due to changes in timing and costs of abandonment activities that occurred at year-end 2016. This increase was partially offset by a decrease of $15 million in North America E&P as a result of production volume decreases and non-core asset dispositions. 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 changes in reserves, capitalized costs, and sales volume mix by field, can also cause changes to our DD&A. Our North America E&P DD&A rate increased in the first quarter of 2017 primarily due to the increased rate in the Gulf of Mexico as a result of the Gunflint field achieving first production in mid-2016. The DD&A rate for International E&P increased primarily due to sales volume mix changes between countries in the current quarter and increased U.K. asset retirement costs due to changes in timing and costs of abandonment activities that occurred at year-end 2016. The following table provides DD&A rates for each segment.
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
$
4 million
in the
first quarter of 2017
versus the same period in 2016. The following table summarizes the components of taxes other than income:
|
|
Three Months Ended March 31,
|
||||||
|
(In millions)
|
2017
|
|
2016
|
||||
|
Production and severance
|
$
|
25
|
|
|
$
|
19
|
|
|
Ad valorem
|
3
|
|
|
13
|
|
||
|
Other
|
11
|
|
|
11
|
|
||
|
Total
|
$
|
39
|
|
|
$
|
43
|
|
28
General and administrative expenses
decreased
$42 million
primarily due to a decrease in pension settlement charges which were reduced in the first three months of 2017 to
$14 million
compared to
$48 million
for the same period in 2016.
Provision (benefit) for income taxes
reflects an effective tax rate from continuing operations of
213%
in the
first quarter
of
2017
, as compared to
(41)%
in the
first quarter
of
2016
. See Note
9
to the consolidated financial statements for more detail discussion concerning the rate changes.
Discontinued operations
are presented net of tax. See the preceding Operations section and Note
6
to the consolidated financial statements for financial information concerning our discontinued operations.
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. A portion of 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, pension settlement losses, or other items that affect comparability also are not allocated to operating segments.
The following table reconciles segment income (loss) to net income (loss):
|
|
Three Months Ended March 31,
|
||||||
|
(In millions)
|
2017
|
|
2016
|
||||
|
North America E&P
|
$
|
(79
|
)
|
|
$
|
(195
|
)
|
|
International E&P
|
93
|
|
|
4
|
|
||
|
Segment income (loss)
|
14
|
|
|
(191
|
)
|
||
|
Items not allocated to segments, net of income taxes
|
(64
|
)
|
|
(169
|
)
|
||
|
Income (loss) from continuing operations
|
(50
|
)
|
|
(360
|
)
|
||
|
Income (loss) from discontinued operations
(a)
|
(4,907
|
)
|
|
(47
|
)
|
||
|
Net income (loss)
|
$
|
(4,957
|
)
|
|
$
|
(407
|
)
|
(a)
We entered into an agreement to sell our Canadian business in the first quarter of 2017. The Canadian business is reflected as discontinued operations in all periods presented.
North America E&P segment loss
decreased
$116 million
after-tax primarily due to higher price realizations, lower production costs, and a reduction in DD&A expenses due to lower net sales volumes in the current period. This was partially offset by a decrease in the income tax benefit which resulted from U.S. valuation allowances in the current period.
International E&P segment income
increased
$89 million
after-tax primarily due to higher price realizations and an increase in sales volumes in E.G. and Libya, and an increase in income from equity investments. During the current quarter our production costs decreased due to lower planned maintenance activities. This was partially offset by an increase in DD&A expenses.
29
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, 2016
.
Accounting Standards Not Yet Adopted
See Note
2
to the consolidated financial statements.
Cash Flows
The following table presents sources and uses of cash and cash equivalents:
|
|
Three Months Ended March 31,
|
||||||
|
(In millions)
|
2017
|
|
2016
|
||||
|
Sources of cash and cash equivalents
|
|
|
|
|
|
||
|
Operating activities - continuing operations
|
$
|
501
|
|
|
$
|
69
|
|
|
Common stock issuance
|
—
|
|
|
1,232
|
|
||
|
Other
|
14
|
|
|
33
|
|
||
|
Total sources of cash and cash equivalents
|
$
|
515
|
|
|
$
|
1,334
|
|
|
Uses of cash and cash equivalents
|
|
|
|
||||
|
Cash additions to property, plant and equipment
|
$
|
(283
|
)
|
|
$
|
(441
|
)
|
|
Deposits for acquisitions
|
(180
|
)
|
|
—
|
|
||
|
Dividends paid
|
(42
|
)
|
|
(34
|
)
|
||
|
Purchases of common stock
|
(7
|
)
|
|
—
|
|
||
|
Other
|
(1
|
)
|
|
—
|
|
||
|
Total uses of cash and cash equivalents
|
$
|
(513
|
)
|
|
$
|
(475
|
)
|
Cash flows generated from operating activities in the first
three months
of
2017
were higher as commodity prices improved compared to the first quarter of 2016. This drove an increase in price realizations in the first
three months
of
2017
. Consolidated average liquid hydrocarbon price realizations increased by more than 65% during the first quarter of 2017 as compared to the prior period. This increase in price realization coupled with our continued focus on cost reduction, including production expense and general & administrative expense, resulted in our increased cash flows generated from operating activities.
Common stock issuance reflects net proceeds received in March 2016 from our public sale of common stock. See Note 18 to the consolidated financial statements for additional information.
Additions to property, plant and equipment in the first
three months
of 2017 were consistent with our Capital Program. The following table shows capital expenditures related to continuing operations by segment and reconciles to additions to property, plant and equipment as presented in the consolidated statements of cash flows (the table below excludes $180 million of aggregate deposits paid into escrow related to the acquisition of Permian assets - see Note 5 to the consolidated financial statements for further information related to this acquisition):
|
|
Three Months Ended March 31,
|
||||||
|
(In millions)
|
2017
|
|
2016
|
||||
|
North America E&P
|
$
|
349
|
|
|
$
|
315
|
|
|
International E&P
|
9
|
|
|
32
|
|
||
|
Corporate
|
1
|
|
|
3
|
|
||
|
Total capital expenditures
|
359
|
|
|
350
|
|
||
|
Decrease (increase) in capital expenditure accrual
|
(76
|
)
|
|
91
|
|
||
|
Total use of cash and cash equivalents for property, plant and equipment
|
$
|
283
|
|
|
$
|
441
|
|
30
Liquidity and Capital Resources
Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, sales of non-core assets, capital market transactions, and our
$3.3 billion
revolving credit facility. At March 31, 2017, we had approximately
$5.8 billion
of liquidity consisting of
$2.5 billion
in cash and cash equivalents and $3.3 billion available under our revolving credit facility. Our working capital requirements are supported by these sources and we may draw on our $3.3 billion revolving 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 are 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.
General economic conditions, commodity prices, and financial, business and other factors could affect our operations and our ability to access the capital markets. Our corporate credit ratings as of March 31, 2017 are: Standard & Poor's Ratings Services BBB- (stable); Fitch Ratings BBB (negative); and Moody's Investor Services, Inc. Ba1 (negative). A downgrade in our credit ratings 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, 2016 for a discussion of how a further downgrade in our credit ratings could affect us.
Capital Resources
Credit Arrangements and Borrowings
At
March 31, 2017
, we had no borrowings against our revolving credit facility.
At
March 31, 2017
, we had
$7.3 billion
in long-term debt outstanding. Our next debt maturity in the amount of
$682 million
is due in the fourth quarter of 2017 and
$854 million
is due in the first quarter of 2018.
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 debt and equity securities.
Pending Asset Disposal
In March 2017, we entered into an agreement to sell our Canadian business for $2.5 billion. Under the terms of the agreement, $1.75 billion, subject to closing adjustments, will be paid to us upon closing and the remaining proceeds will be paid in the first quarter of 2018. The sale is expected to close in mid-2017 concurrent with a related transaction between Shell and Canadian Natural Resources. See Note 6 to the consolidated financial statements for additional information.
Pending Asset Acquisitions
In March 2017, we entered into separate agreements to acquire approximately 91,000 net acres in the Permian basin, including over 70,000 net acres in the Northern Delaware basin of New Mexico for $1.8 billion, excluding closing adjustments. We paid $180 million in aggregate deposits into escrow related to these acquisitions during the first quarter of 2017. We closed on the acquisition from BC Operating, Inc. and other entities with cash on hand on May 1, 2017 and expect to close our remaining acquisition from Black Mountain Oil & Gas and other private sellers in the second quarter of 2017 with cash on hand. See Note 5 to the consolidated financial statements for additional information.
31
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
28%
at
March 31, 2017
, compared to
21%
at
December 31, 2016
.
|
|
March 31,
|
|
December 31,
|
||||
|
(In millions)
|
2017
|
|
2016
|
||||
|
Long-term debt due within one year
|
$
|
1,541
|
|
|
$
|
686
|
|
|
Long-term debt
|
5,723
|
|
|
6,581
|
|
||
|
Total debt
|
$
|
7,264
|
|
|
$
|
7,267
|
|
|
Cash and cash equivalents
|
$
|
2,490
|
|
|
$
|
2,488
|
|
|
Equity
|
$
|
12,584
|
|
|
$
|
17,541
|
|
|
Calculation:
|
|
|
|
|
|
||
|
Total debt
|
$
|
7,264
|
|
|
$
|
7,267
|
|
|
Minus cash and cash equivalents
|
2,490
|
|
|
2,488
|
|
||
|
Total debt minus cash, cash equivalents
|
$
|
4,774
|
|
|
$
|
4,779
|
|
|
Total debt
|
$
|
7,264
|
|
|
$
|
7,267
|
|
|
Plus equity
|
12,584
|
|
|
17,541
|
|
||
|
Minus cash and cash equivalents
|
2,490
|
|
|
2,488
|
|
||
|
Total debt plus equity minus cash, cash equivalents
|
$
|
17,358
|
|
|
$
|
22,320
|
|
|
Cash-adjusted debt-to-capital ratio
|
28
|
%
|
|
21
|
%
|
||
Capital Requirements
Capital Spending
We entered into agreements to purchase Permian assets for $1.8 billion, excluding closing adjustments, discussed in more detail in Note 5 to the consolidated financial statements. As a result, we increased our approved Capital Program for
2017
from
$2.2 billion
to approximately $2.4 billion as a result of these acquisitions.
Other Expected Cash Outflows
On April 26, 2017, our Board of Directors approved a dividend of $0.05 per share for the
first quarter
of 2017 payable June 12, 2017 to stockholders of record at the close of business on May 17, 2017.
As of
March 31, 2017
, we plan to make contributions of up to
$47 million
to our funded pension plans during the remainder of 2017.
Contractual Cash Obligations
As of
March 31, 2017
, there are no material changes to our consolidated cash obligations to make future payments under existing contracts, as disclosed in our 2016 Annual Report on Form 10-K, except for the agreements we entered into to acquire Permian acreage for $1.8 billion, excluding closing adjustments. See Note 5 to the consolidated financial statements for additional information. Additionally, in March 2017, we entered into an agreement to sell our Canadian business for $2.5 billion. The sale is expected to close in mid-2017 concurrent with a related transaction between Shell and Canadian Natural Resources. See Note 6 to the consolidated financial statements for additional information. As a result, our Canadian business is reflected as discontinued operations in the consolidated financial statements for all periods presented. As of March 31, 2017, our consolidated contractual cash obligations from our continuing operations has decreased by $1,107 million from December 31, 2016 primarily due to obligations relating to the announced sale of our Canadian business. Our purchase obligations under oil and gas activities decreased by $67 million, service and materials contracts decreased $628 million and transportation and related contracts decreased $281 million when comparing March 31, 2017 to December 31, 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. We executed a settlement agreement with the North Dakota Department of Health relating to this matter in the fourth quarter of 2016 that includes a base penalty of $294,000 that will be reduced under the terms by mitigating corrective actions. 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.
In March 2016 we proactively notified the U.K. environmental regulator Business, Energy and Industrial Strategy (“BEIS”) that we had recognized an error in our carbon dioxide (“CO2”) emissions reporting. In December 2016 we received a
32
‘Notice of Intent to Impose a Civil Penalty’ from BEIS for the self-disclosed underreporting of CO2 emissions. The letter advised that the penalty for this event had initially been set at €946,360, however BEIS had reduced the amount to €630,906 in recognition of our self-reporting and proactive cooperation with the investigation. In February 2017 we received the final letter from BEIS, the ‘Civil Penalty Notice’ that confirmed the penalty. The fixed penalty is set by European Union legislation and is calculated in Euros. The payment is made to the U.K. regulator in GBP using conversion tables also defined by the European Union. The actual sum paid in April 2017 was £537,295.
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, asset acquisitions and dispositions, 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:
|
•
|
conditions in the oil and gas industry, including supply and demand levels for crude oil and condensate, NGLs, natural gas and synthetic crude oil and the resulting impact on price;
|
|
•
|
changes in expected reserve or production levels;
|
|
•
|
changes in political and 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;
|
|
•
|
risks related to our hedging activities;
|
|
•
|
capital available for exploration and development;
|
|
•
|
the inability of any party to satisfy closing conditions with respect to our asset acquisitions and dispositions;
|
|
•
|
drilling and operating risks;
|
|
•
|
well production timing;
|
|
•
|
availability of drilling rigs, materials and labor, including the costs associated therewith;
|
|
•
|
difficulty in obtaining necessary approvals and permits;
|
|
•
|
non-performance by third parties of contractual obligations;
|
|
•
|
unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto;
|
|
•
|
cyber-attacks;
|
|
•
|
changes in safety, health, environmental, tax and other regulations;
|
|
•
|
other geological, operating and economic considerations; and
|
|
•
|
the risk factors, forward-looking statements and challenges and uncertainties described in our 2016 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other filings with the SEC.
|
All forward-looking statements included in this report are based on information available to us on the date of this report. Except as required by law, we undertake no obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.
33
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 2016 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
three months
of 2017, we entered into crude oil and natural gas derivatives, indexed to NYMEX WTI and Henry Hub, related to a portion of our forecasted North America E&P sales. The following tables provide a summary of open positions as of
March 31, 2017
and the weighted average price for those contracts:
|
(a)
|
Call options settle monthly.
|
|
(a)
|
Subsequent to March 31, 2017, we entered into
70,000
MMBTU/day of three-way collars for January - December 2018 with a ceiling price of
$3.62
, a floor price of
$3.00
, and a sold put price of
$2.50
and
40,000
MMBTU/day of three-way collars for January - March 2018 with a ceiling price of
$4.47
, a floor price of
$3.40
, and a sold put price of
$2.75
.
|
34
The following table provides a sensitivity analysis of the projected incremental effect on income (loss) from operations of a hypothetical 10% change in NYMEX WTI and Henry Hub prices on our open commodity derivative instruments as of
March 31, 2017
.
|
(In millions)
|
Hypothetical Price Increase of 10%
|
Hypothetical Price Decrease of 10%
|
||||
|
|
|
|
||||
|
Crude oil derivatives
|
$
|
(46
|
)
|
$
|
36
|
|
|
Natural gas derivatives
|
(14
|
)
|
12
|
|
||
|
Total
|
$
|
(60
|
)
|
$
|
48
|
|
Interest Rate Risk
Sensitivity analysis of the incremental effect of a hypothetical 10% decrease in interest rates on financial assets and liabilities as of
March 31, 2017
, is provided in the following table.
|
(In millions)
|
Fair Value
|
|
Incremental Change in Fair Value
|
||||
|
Financial assets (liabilities):
(a)
|
|
|
|
||||
|
Interest rate cash flow hedges
|
$
|
65
|
|
(b)
|
$
|
(17
|
)
|
|
Interest rate fair value hedges
|
$
|
2
|
|
(b)
|
$
|
1
|
|
|
Long term debt, including amounts due within one year
|
$
|
(7,535
|
)
|
(b)(c)
|
$
|
(257
|
)
|
|
(a)
|
Fair value of cash and cash equivalents, receivables, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.
|
|
(b)
|
Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.
|
|
(c)
|
Excludes capital leases.
|
Item 4. Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this Report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as of
March 31, 2017
.
During the
first quarter of 2017
, 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.
35
Part II – OTHER INFORMATION
Item 1. Legal 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.
The following is a summary of certain proceedings involving us that were pending or contemplated as of March 31, 2017 under federal, state and international environmental laws:
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. We executed a settlement agreement with the North Dakota Department of Health relating to this matter in the fourth quarter of 2016 that includes a base penalty of $294,000 that will be reduced under the terms by mitigating corrective actions. 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.
In March 2016 we proactively notified the U.K. environmental regulator Business, Energy and Industrial Strategy (“BEIS”) that we had recognized an error in our carbon dioxide (“CO2”) emissions reporting. In December 2016 we received a ‘Notice of Intent to Impose a Civil Penalty’ from BEIS for the self-disclosed underreporting of CO2 emissions. The letter advised that the penalty for this event had initially been set at €946,360, however BEIS had reduced the amount to €630,906 in recognition of our self-reporting and proactive cooperation with the investigation. In February 2017 we received the final letter from BEIS, the ‘Civil Penalty Notice’ that confirmed the penalty. The fixed penalty is set by European Union legislation and is calculated in Euros. The payment is made to the U.K. regulator in GBP using conversion tables also defined by the European Union. The actual sum paid in April 2017 was £537,295.
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
2016
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
March 31, 2017
.
|
Period
|
Total Number of
Shares
Purchased
(a)
|
|
Average
Price Paid
per Share
|
|
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs
(b)
|
|
Approximate
Dollar Value of
Shares that May
Yet Be Purchased
Under the Plans
or Programs
(b)
|
||||
|
01/01/17 - 01/31/17
|
5,334
|
|
|
$17.68
|
|
—
|
|
|
$
|
1,500,285,529
|
|
|
02/01/17 - 02/28/17
|
23,190
|
|
|
$15.87
|
|
—
|
|
|
$
|
1,500,285,529
|
|
|
03/01/17 - 03/31/17
|
347,569
|
|
|
$16.38
|
|
—
|
|
|
$
|
1,500,285,529
|
|
|
Total
|
376,093
|
|
|
$16.37
|
|
—
|
|
|
|
||
|
(a)
|
376,093
shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.
|
|
(b)
|
In January 2006, we announced a $2.0 billion share repurchase program. Our Board of directors subsequently increased the authorization for repurchases under the program by $500 million in January 2007, by $500 million in May 2007, by $2.0 billion in July 2007, and by $1.2 billion in December 2013, for a total authorized amount of $6.2 billion. The remaining share repurchase authorization as of
March 31, 2017
is
$1.5 billion
. No repurchases were made under the program in the first quarter of 2017.
|
Item 6. Exhibits
The information required by this Item 6 is set forth in the Exhibit Index accompanying this Form 10-Q.
36
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
May 5, 2017
|
|
MARATHON OIL CORPORATION
|
|
|
|
|
|
|
By:
|
/s/ Gary E. Wilson
|
|
|
|
Gary E. Wilson
|
|
|
|
Vice President, Controller and Chief Accounting Officer
|
|
|
|
(Duly Authorized Officer)
|
37
Exhibit Index
|
|
|
|
Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
|
|||||
|
Exhibit Number
|
|
Exhibit Description
|
Form
|
|
Exhibit
|
|
Filing Date
|
|
|
3.1
|
|
10-Q
|
|
3.1
|
|
8/8/2013
|
|
|
|
3.2
|
|
8-K
|
|
3.1
|
|
3/1/2016
|
|
|
|
3.3
|
|
10-K
|
|
3.3
|
|
2/28/2014
|
|
|
|
4.1
|
|
10-K
|
|
4.2
|
|
2/28/2014
|
|
|
|
10.1*
|
|
Share Purchase Agreement, dated as of March 8, 2017, by and among Marathon Oil Dutch Holdings B.V., as Seller, and 10084751 Canada Limited, as a Buyer and Canadian Natural Resources Limited, as a Buyer, in respect of Marathon Oil Canada Corporation.
|
|
|
|
|
|
|
|
10.2
|
|
8-K
|
|
10.1
|
|
3/31/2017
|
|
|
|
10.3
|
|
8-K
|
|
10.2
|
|
3/31/2017
|
|
|
|
31.1*
|
|
Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
|
|
|
|
|
|
|
|
31.2*
|
|
Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
|
|
|
|
|
|
|
|
32.1*
|
|
Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350
|
|
|
|
|
|
|
|
32.2*
|
|
Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
|
|
|
|
|
|
|
|
101.INS*
|
|
XBRL Instance Document
|
|
|
|
|
|
|
|
101.SCH*
|
|
XBRL Taxonomy Extension Schema
|
|
|
|
|
|
|
|
101.CAL*
|
|
XBRL Taxonomy Extension Calculation Linkbase
|
|
|
|
|
|
|
|
101.DEF*
|
|
XBRL Taxonomy Extension Definition Linkbase
|
|
|
|
|
|
|
|
101.LAB*
|
|
XBRL Taxonomy Extension Label Linkbase
|
|
|
|
|
|
|
|
101.PRE*
|
|
XBRL Taxonomy Extension Presentation Linkbase
|
|
|
|
|
|
|
|
*
|
|
Filed herewith.
|
|
|
|
|
|
|