MARATHON OIL CORP
10-Qs and 10-Ks
PROXIES
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
|
(Mark One)
|
|
|
[X]
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
|
|
|
For the Quarterly Period Ended March 31, 2016
|
OR
|
[ ]
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
|
|
|
For the transition period from _____ to _____
|
Commission file number 1-5153
Marathon Oil Corporation
(Exact name of registrant as specified in its charter)
|
Delaware
|
25-0996816
|
|
|
(State or other jurisdiction of incorporation or organization)
|
(I.R.S. Employer Identification No.)
|
|
5555 San Felipe Street, Houston, TX 77056-2723
(Address of principal executive offices)
(713) 629-6600
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes
R
No
£
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes
R
No
£
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
|
Large accelerated filer
þ
|
Accelerated filer
o
|
|
Non-accelerated filer
o
(Do not check if a smaller reporting company)
|
Smaller reporting company
o
|
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes
o
No
þ
There were
847,648,273
shares of Marathon Oil Corporation common stock outstanding as of
April 29, 2016
.
MARATHON OIL CORPORATION
Unless the context otherwise indicates, references to “Marathon Oil,” “we,” “our,” or “us” in this Form 10-Q are references to Marathon Oil Corporation, including its wholly-owned and majority-owned subsidiaries, and its ownership interests in equity method investees (corporate entities, partnerships, limited liability companies and other ventures over which Marathon Oil exerts significant influence by virtue of its ownership interest).
For certain industry specific terms used in this Form 10-Q, please see "Definitions" in our
2015
Annual Report on Form 10-K.
|
|
Table of Contents
|
|
|
|
Page
|
|
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
1
Part I - Financial Information
Item 1. Financial Statements
MARATHON OIL CORPORATION
Consolidated Statements of Income (Unaudited)
|
Three Months Ended
|
|||||||
|
March 31,
|
|||||||
|
(In millions, except per share data)
|
2016
|
2015
|
|||||
|
Revenues and other income:
|
|
|
|||||
|
Sales and other operating revenues, including related party
|
$
|
714
|
|
$
|
1,280
|
|
|
|
Marketing revenues
|
58
|
|
204
|
|
|||
|
Income from equity method investments
|
14
|
|
36
|
|
|||
|
Net gain (loss) on disposal of assets
|
(60
|
)
|
1
|
|
|||
|
Other income
|
4
|
|
11
|
|
|||
|
Total revenues and other income
|
730
|
|
1,532
|
|
|||
|
Costs and expenses:
|
|
|
|||||
|
Production
|
328
|
|
444
|
|
|||
|
Marketing, including purchases from related parties
|
58
|
|
205
|
|
|||
|
Other operating
|
109
|
|
107
|
|
|||
|
Exploration
|
24
|
|
90
|
|
|||
|
Depreciation, depletion and amortization
|
609
|
|
821
|
|
|||
|
Impairments
|
1
|
|
—
|
|
|||
|
Taxes other than income
|
48
|
|
67
|
|
|||
|
General and administrative
|
151
|
|
171
|
|
|||
|
Total costs and expenses
|
1,328
|
|
1,905
|
|
|||
|
Income (loss) from operations
|
(598
|
)
|
(373
|
)
|
|||
|
Net interest and other
|
(85
|
)
|
(47
|
)
|
|||
|
Income (loss) before income taxes
|
(683
|
)
|
(420
|
)
|
|||
|
Provision (benefit) for income taxes
|
(276
|
)
|
(144
|
)
|
|||
|
Net income (loss)
|
$
|
(407
|
)
|
$
|
(276
|
)
|
|
|
Net income (loss) per share:
|
|
|
|
|
|||
|
Basic
|
$
|
(0.56
|
)
|
$
|
(0.41
|
)
|
|
|
Diluted
|
$
|
(0.56
|
)
|
$
|
(0.41
|
)
|
|
|
Dividends per share
|
$
|
0.05
|
|
$
|
0.21
|
|
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|||
|
Basic
|
730
|
|
675
|
|
|||
|
Diluted
|
730
|
|
675
|
|
|||
The accompanying notes are an integral part of these consolidated financial statements
.
2
MARATHON OIL CORPORATION
Consolidated Statements of Comprehensive Income (Unaudited)
|
Three Months Ended
|
|||||||
|
March 31,
|
|||||||
|
(In millions)
|
2016
|
2015
|
|||||
|
Net income (loss)
|
$
|
(407
|
)
|
$
|
(276
|
)
|
|
|
Other comprehensive income (loss)
|
|
|
|
|
|||
|
Postretirement and postemployment plans
|
|
|
|
|
|||
|
Change in actuarial loss and other
|
(24
|
)
|
76
|
|
|||
|
Income tax provision (benefit)
|
9
|
|
(27
|
)
|
|||
|
Postretirement and postemployment plans, net of tax
|
(15
|
)
|
49
|
|
|||
|
Comprehensive income (loss)
|
$
|
(422
|
)
|
$
|
(227
|
)
|
|
The accompanying notes are an integral part of these consolidated financial statements
.
3
MARATHON OIL CORPORATION
Consolidated Balance Sheets (Unaudited)
|
March 31,
|
December 31,
|
||||||
|
(In millions, except per share data)
|
2016
|
2015
|
|||||
|
Assets
|
|
|
|||||
|
Current assets:
|
|
|
|||||
|
Cash and cash equivalents
|
$
|
2,072
|
|
$
|
1,221
|
|
|
|
Receivables, less reserve of $4 and $4
|
779
|
|
912
|
|
|||
|
Inventories
|
306
|
|
313
|
|
|||
|
Other current assets
|
111
|
|
144
|
|
|||
|
Total current assets
|
3,268
|
|
2,590
|
|
|||
|
Equity method investments
|
959
|
|
1,003
|
|
|||
|
Property, plant and equipment, less accumulated depreciation,
|
|
|
|
|
|||
|
depletion and amortization of $22,763 and $23,260
|
26,737
|
|
27,061
|
|
|||
|
Goodwill
|
115
|
|
115
|
|
|||
|
Other noncurrent assets
|
1,789
|
|
1,542
|
|
|||
|
Total assets
|
$
|
32,868
|
|
$
|
32,311
|
|
|
|
Liabilities
|
|
|
|
|
|||
|
Current liabilities:
|
|
|
|
|
|||
|
Accounts payable
|
$
|
1,084
|
|
$
|
1,313
|
|
|
|
Payroll and benefits payable
|
79
|
|
133
|
|
|||
|
Accrued taxes
|
151
|
|
132
|
|
|||
|
Other current liabilities
|
211
|
|
150
|
|
|||
|
Long-term debt due within one year
|
1
|
|
1
|
|
|||
|
Total current liabilities
|
1,526
|
|
1,729
|
|
|||
|
Long-term debt
|
7,280
|
|
7,276
|
|
|||
|
Deferred tax liabilities
|
2,368
|
|
2,441
|
|
|||
|
Defined benefit postretirement plan obligations
|
446
|
|
403
|
|
|||
|
Asset retirement obligations
|
1,614
|
|
1,601
|
|
|||
|
Deferred credits and other liabilities
|
283
|
|
308
|
|
|||
|
Total liabilities
|
13,517
|
|
13,758
|
|
|||
|
Commitments and contingencies
|
|
|
|
|
|||
|
Stockholders’ Equity
|
|
|
|
|
|||
|
Preferred stock – no shares issued or outstanding (no par value,
|
|||||||
|
26 million shares authorized)
|
—
|
|
—
|
|
|||
|
Common stock:
|
|
|
|
|
|||
|
Issued – 937 million shares and 770 million shares (par value $1 per share,
|
|||||||
|
1.1 billion shares authorized)
|
937
|
|
770
|
|
|||
|
Securities exchangeable into common stock – no shares issued or
|
|
|
|
|
|||
|
outstanding (no par value, 29 million shares authorized)
|
—
|
|
—
|
|
|||
|
Held in treasury, at cost – 89 million and 93 million shares
|
(3,397
|
)
|
(3,554
|
)
|
|||
|
Additional paid-in capital
|
7,428
|
|
6,498
|
|
|||
|
Retained earnings
|
14,533
|
|
14,974
|
|
|||
|
Accumulated other comprehensive loss
|
(150
|
)
|
(135
|
)
|
|||
|
Total stockholders' equity
|
19,351
|
|
18,553
|
|
|||
|
Total liabilities and stockholders' equity
|
$
|
32,868
|
|
$
|
32,311
|
|
|
The accompanying notes are an integral part of these consolidated financial statements
.
4
MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows (Unaudited)
|
Three Months Ended
|
|||||||
|
March 31,
|
|||||||
|
(In millions)
|
2016
|
2015
|
|||||
|
Increase (decrease) in cash and cash equivalents
|
|
|
|||||
|
Operating activities:
|
|
|
|
|
|||
|
Net income (loss)
|
$
|
(407
|
)
|
$
|
(276
|
)
|
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|||
|
Deferred income taxes
|
(320
|
)
|
(179
|
)
|
|||
|
Depreciation, depletion and amortization
|
609
|
|
821
|
|
|||
|
Impairments
|
1
|
|
—
|
|
|||
|
Pension and other postretirement benefits, net
|
14
|
|
(7
|
)
|
|||
|
Exploratory dry well costs and unproved property impairments
|
11
|
|
67
|
|
|||
|
Net (gain) loss on disposal of assets
|
60
|
|
(1
|
)
|
|||
|
Equity method investments, net
|
30
|
|
3
|
|
|||
|
Changes in:
|
|
|
|||||
|
Current receivables
|
133
|
|
388
|
|
|||
|
Inventories
|
7
|
|
(22
|
)
|
|||
|
Current accounts payable and accrued liabilities
|
(121
|
)
|
(469
|
)
|
|||
|
All other operating, net
|
57
|
|
(16
|
)
|
|||
|
Net cash provided by operating activities
|
74
|
|
309
|
|
|||
|
Investing activities:
|
|
|
|
|
|||
|
Additions to property, plant and equipment
|
(454
|
)
|
(1,452
|
)
|
|||
|
Disposal of assets
|
17
|
|
2
|
|
|||
|
Investments - return of capital
|
14
|
|
10
|
|
|||
|
All other investing, net
|
2
|
|
(2
|
)
|
|||
|
Net cash used in investing activities
|
(421
|
)
|
(1,442
|
)
|
|||
|
Financing activities:
|
|
|
|
|
|||
|
Common stock issuance
|
1,232
|
|
—
|
|
|||
|
Dividends paid
|
(34
|
)
|
(142
|
)
|
|||
|
All other financing, net
|
—
|
|
4
|
|
|||
|
Net cash provided by (used in) financing activities
|
1,198
|
|
(138
|
)
|
|||
|
Effect of exchange rate on cash and cash equivalents
|
—
|
|
(1
|
)
|
|||
|
Net increase (decrease) in cash and cash equivalents
|
851
|
|
(1,272
|
)
|
|||
|
Cash and cash equivalents at beginning of period
|
1,221
|
|
2,398
|
|
|||
|
Cash and cash equivalents at end of period
|
$
|
2,072
|
|
$
|
1,126
|
|
|
The accompanying notes are an integral part of these consolidated financial statements
.
5
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
1
. Basis of Presentation
These consolidated financial statements are unaudited; however, in the opinion of management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported. All such adjustments are of a normal recurring nature unless disclosed otherwise. These consolidated financial statements, including notes, have been prepared in accordance with the applicable rules of the SEC and do not include all of the information and disclosures required by U.S. GAAP for complete financial statements.
These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our
2015
Annual Report on Form 10-K. The results of operations for the
first quarter of
2016
are not necessarily indicative of the results to be expected for the full year.
2
. Accounting Standards
Not Yet Adopted
In March 2016, the FASB issued a new accounting standards update that changes several aspects of accounting for share-based payment transactions, including a requirement to recognize all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This standard is effective for us in the first quarter of 2017 and varying transition methods (modified retrospective, retrospective or prospective) should be applied to different provisions of the standard. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.
In February 2016, the FASB issued a new lease accounting standard, which requires lessees to recognize most leases, including operating leases, on the balance sheet as a right of use asset and lease liability. Short-term leases can continue being accounted for off balance sheet based on a policy election. This standard is effective for us in the first quarter of 2019 and should be applied using a modified retrospective approach at the beginning of the earliest period presented in the financial statements. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it may have on our consolidated results of operations, financial position or cash flows.
In January 2016, the FASB issued an accounting standards update that addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. This standard is effective for us in the first quarter of 2018. Early adoption is allowed for certain provisions. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In July 2015, the FASB issued an update that requires an entity to measure inventory at the lower of cost and net realizable value. This excludes inventory measured using LIFO or the retail inventory method. This standard is effective for us in the first quarter of 2017 and will be applied prospectively. Early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In August 2014, the FASB issued an update that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards. This standard is effective for us for the annual period ending after December 15, 2016 and for annual periods and interim periods thereafter. Early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In May 2014, the FASB issued an update that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. Among other things, the standard requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for us in the first quarter of 2018 and should be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.
Recently Adopted
In May 2015, the FASB issued an update that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The amendment also
6
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
removes certain disclosure requirements regarding all investments that are eligible to be measured using the net asset value per share practical expedient and only requires certain disclosures on those investments for which an entity elects to use the net asset value per share expedient. This standard is effective for us in the first quarter of 2016 and was applied on a retrospective basis. This standard only modifies disclosure requirements; as such, there was no impact on our consolidated results of operations, financial position or cash flows.
In February 2015, the FASB issued an amendment to the guidance for determining whether an entity is a variable interest entity ("VIE"). The standard does not add or remove any of the five characteristics that determine whether an entity is a VIE. However, it does change the manner in which a reporting entity assesses one of the characteristics. In particular, when decision-making over the entity’s most significant activities has been outsourced, the standard changes how a reporting entity assesses if the equity holders at risk lack decision making rights. This standard is effective for us in the first quarter of 2016. The adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.
3
. Variable Interest Entity
The owners of the Athabasca Oil Sands Project, in which we hold a
20%
undivided interest, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton, Alberta, Canada. Costs under this contract are accrued and recorded on a monthly basis, with current liabilities of
$2 million
recorded at
March 31, 2016
and December 31, 2015. This contract qualifies as a variable interest contractual arrangement, and the Corridor Pipeline qualifies as a VIE. We hold a variable interest but are not the primary beneficiary because our shipments are only 20% of the total; therefore, the Corridor Pipeline is not consolidated by us. Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was
$472 million
as of
March 31, 2016
. The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term.
|
4
.
|
Income (Loss) per Common Share
|
Basic income (loss) per share is based on the weighted average number of common shares outstanding. Diluted income per share assumes exercise of stock options, provided the effect is not antidilutive. The per share calculations below exclude
13 million
stock options for the
first
three months of
2016
and
2015
that were antidilutive.
|
Three Months Ended March 31,
|
|||||||
|
(In millions, except per share data)
|
2016
|
2015
|
|||||
|
Net income (loss)
|
$
|
(407
|
)
|
$
|
(276
|
)
|
|
|
Weighted average common shares outstanding
|
730
|
|
675
|
|
|||
|
Weighted average common shares, diluted
|
730
|
|
675
|
|
|||
|
Net income (loss) per share:
|
|||||||
|
Basic
|
$
|
(0.56
|
)
|
$
|
(0.41
|
)
|
|
|
Diluted
|
$
|
(0.56
|
)
|
$
|
(0.41
|
)
|
|
|
5
.
|
Dispositions
|
North America E&P Segment
In April 2016, we entered into agreements to sell our Wyoming upstream and midstream assets for proceeds of
$870 million
, before closing adjustments. The upstream properties are comprised mainly of waterflood developments in the Big Horn and Wind River basins. The midstream assets include the 570-mile Red Butte pipeline. We expect the transaction to close mid-year 2016.
In March and April 2016, we entered into separate agreements to sell our 10% working interest in the outside-operated Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Colorado, and certain undeveloped acreage in West Texas for a combined total of approximately
$80 million
, before closing adjustments. The transactions are expected to close mid-year 2016.
7
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
6
. Segment Information
We have three reportable operating segments. Each of these segments is organized and managed based upon both geographic location and the nature of the products and services it offers.
|
•
|
N.A. E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in North America;
|
|
•
|
Int'l E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.; and
|
|
•
|
Oil Sands Mining (“OSM”) – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
|
Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”). Segment income represents income which excludes certain items not allocated to segments, net of income taxes, attributable to the operating segments. A portion of our corporate and operations support general and administrative costs are not allocated to the operating segments. These unallocated costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Gains or losses on dispositions, certain impairments, change in tax expense associated with a tax rate change, unrealized gains or losses on commodity derivative instruments, or other items that affect comparability (as determined by the CODM) also are not allocated to operating segments.
|
|
Three Months Ended March 31, 2016
|
||||||||||||||||||
|
Not Allocated
|
|||||||||||||||||||
|
(In millions)
|
N.A. E&P
|
Int'l E&P
|
OSM
|
to Segments
|
Total
|
||||||||||||||
|
Sales and other operating revenues
|
$
|
493
|
|
$
|
96
|
|
$
|
148
|
|
$
|
(23
|
)
|
(c)
|
$
|
714
|
|
|||
|
Marketing revenues
|
31
|
|
15
|
|
12
|
|
—
|
|
58
|
|
|||||||||
|
Total revenues
|
524
|
|
111
|
|
160
|
|
(23
|
)
|
772
|
|
|||||||||
|
Income from equity method investments
|
—
|
|
14
|
|
—
|
|
—
|
|
14
|
|
|||||||||
|
Net gain (loss) on disposal of assets and other income
|
1
|
|
6
|
|
—
|
|
(63
|
)
|
(d)
|
(56
|
)
|
||||||||
|
Less:
|
|||||||||||||||||||
|
Production expenses
|
134
|
|
53
|
|
141
|
|
—
|
|
328
|
|
|||||||||
|
Marketing costs
|
32
|
|
14
|
|
12
|
|
—
|
|
58
|
|
|||||||||
|
Exploration expenses
|
18
|
|
6
|
|
—
|
|
—
|
|
|
24
|
|
||||||||
|
Depreciation, depletion and amortization
|
487
|
|
50
|
|
60
|
|
12
|
|
609
|
|
|||||||||
|
Impairments
|
1
|
|
—
|
|
—
|
|
—
|
|
1
|
|
|||||||||
|
Other expenses
(a)
|
118
|
|
16
|
|
7
|
|
119
|
|
(e)
|
260
|
|
||||||||
|
Taxes other than income
|
42
|
|
—
|
|
5
|
|
1
|
|
48
|
|
|||||||||
|
Net interest and other
|
—
|
|
—
|
|
—
|
|
85
|
|
85
|
|
|||||||||
|
Income tax benefit
|
(112
|
)
|
(12
|
)
|
(17
|
)
|
(135
|
)
|
(276
|
)
|
|||||||||
|
Segment income (loss) / Net income (loss)
|
$
|
(195
|
)
|
$
|
4
|
|
$
|
(48
|
)
|
$
|
(168
|
)
|
$
|
(407
|
)
|
||||
|
Capital expenditures
(b)
|
$
|
315
|
|
$
|
32
|
|
$
|
9
|
|
$
|
3
|
|
$
|
359
|
|
||||
|
(a)
|
Includes other operating expenses and general and administrative expenses.
|
(b)
Includes accruals.
|
(c)
|
Unrealized loss on commodity derivative instruments.
|
|
(d)
|
Related to the net loss on disposal of assets (see Note
5
).
|
|
(e)
|
Includes pension settlement loss of
$48 million
and severance related expenses associated with workforce reductions of
$7 million
(see Note
7
).
|
8
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
|
|
Three Months Ended March 31, 2015
|
||||||||||||||||||
|
Not Allocated
|
|||||||||||||||||||
|
(In millions)
|
N.A. E&P
|
Int'l E&P
|
OSM
|
to Segments
|
Total
|
||||||||||||||
|
Sales and other operating revenues
|
$
|
850
|
|
$
|
182
|
|
$
|
225
|
|
$
|
23
|
|
(c)
|
$
|
1,280
|
|
|||
|
Marketing revenues
|
178
|
|
26
|
|
—
|
|
—
|
|
204
|
|
|||||||||
|
Total revenues
|
1,028
|
|
208
|
|
225
|
|
23
|
|
1,484
|
|
|||||||||
|
Income from equity method investments
|
—
|
|
36
|
|
—
|
|
—
|
|
36
|
|
|||||||||
|
Net gain on disposal of assets and other income
|
—
|
|
10
|
|
1
|
|
1
|
|
12
|
|
|||||||||
|
Less:
|
|||||||||||||||||||
|
Production expenses
|
202
|
|
67
|
|
175
|
|
—
|
|
444
|
|
|||||||||
|
Marketing costs
|
180
|
|
25
|
|
—
|
|
—
|
|
205
|
|
|||||||||
|
Exploration expenses
|
35
|
|
55
|
|
—
|
|
—
|
|
90
|
|
|||||||||
|
Depreciation, depletion and amortization
|
683
|
|
64
|
|
62
|
|
12
|
|
821
|
|
|||||||||
|
Other expenses
(a)
|
117
|
|
23
|
|
9
|
|
129
|
|
(d)
|
278
|
|
||||||||
|
Taxes other than income
|
61
|
|
—
|
|
5
|
|
1
|
|
67
|
|
|||||||||
|
Net interest and other
|
—
|
|
—
|
|
—
|
|
47
|
|
47
|
|
|||||||||
|
Income tax benefit
|
(89
|
)
|
(3
|
)
|
(6
|
)
|
(46
|
)
|
(144
|
)
|
|||||||||
|
Segment income (loss) / Net income (loss)
|
$
|
(161
|
)
|
$
|
23
|
|
$
|
(19
|
)
|
$
|
(119
|
)
|
$
|
(276
|
)
|
||||
|
Capital expenditures
(b)
|
$
|
933
|
|
$
|
146
|
|
$
|
21
|
|
$
|
2
|
|
$
|
1,102
|
|
||||
|
(a)
|
Includes other operating expenses and general and administrative expenses.
|
|
(b)
|
Includes accruals.
|
|
(c)
|
Unrealized gain on commodity derivative instruments.
|
|
(d)
|
Includes
$43 million
of severance related expenses associated with a workforce reduction and pension settlement loss of $
17 million
(see Note
7
).
|
7
. Defined Benefit Postretirement Plans
The following summarizes the components of net periodic benefit cost:
|
|
Three Months Ended March 31,
|
||||||||||||||
|
|
Pension Benefits
|
Other Benefits
|
|||||||||||||
|
(In millions)
|
2016
|
2015
|
2016
|
2015
|
|||||||||||
|
Service cost
|
$
|
6
|
|
$
|
12
|
|
$
|
1
|
|
$
|
1
|
|
|||
|
Interest cost
|
11
|
|
14
|
|
3
|
|
3
|
|
|||||||
|
Expected return on plan assets
|
(15
|
)
|
(19
|
)
|
—
|
|
—
|
|
|||||||
|
Amortization:
|
|
|
|
|
|
|
|||||||||
|
– prior service cost (credit)
|
(2
|
)
|
1
|
|
(1
|
)
|
(1
|
)
|
|||||||
|
– actuarial loss
|
3
|
|
7
|
|
—
|
|
—
|
|
|||||||
|
Net settlement loss
(a)
|
48
|
|
17
|
|
—
|
|
—
|
|
|||||||
|
Net curtailment loss (gain)
(b)
|
—
|
|
1
|
|
—
|
|
(6
|
)
|
|||||||
|
Net periodic benefit cost
|
$
|
51
|
|
|
$
|
33
|
|
|
$
|
3
|
|
|
$
|
(3
|
)
|
|
(a)
|
Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan's total service and interest cost for that year.
|
|
(b)
|
Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans.
|
During the
first three months of 2016
, we recorded the effects of settlements of our U.S. pension plans. As required, we remeasured the plans' assets and liabilities as of the applicable balance sheet dates. The cumulative effects of these events are included in the remeasurement and reflected in both the pension liability and net periodic benefit cost.
During the
first three months of 2016
, we made contributions of
$14 million
to our funded pension plans. We expect to make additional contributions up to an estimated
$48 million
to our funded pension plans over the remainder of
2016
. During the
first three months of 2016
, we made payments of
$19 million
and
$5 million
related to unfunded pension plans and other postretirement benefit plans, respectively.
9
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
8
. Income Taxes
Effective Tax Rate
The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The difference between the total provision and the sum of the amounts allocated to segments is reported in the “Not Allocated to Segments” column of the tables in Note
6
.
Our effective income tax rates for the
first three months of 2016
and
2015
were
40%
and
34%
. In Libya, uncertainty remains around the timing of future production and sales levels. Reliable estimates of
2016
and
2015
Libyan annual ordinary income from our operations could not be made and the range of possible scenarios in the worldwide annual effective tax rate calculation demonstrates significant variability. Thus, the tax benefit applicable to Libyan ordinary loss was recorded as a discrete item in the
first three months of 2016
and
2015
. For the
first three months of 2016
and
2015
, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss). Excluding Libya, the effective tax rates, would be
39%
and
31%
for the
first three months of 2016
and
2015
. The change was driven by a shift in jurisdictional income.
Deferred Tax Assets
In connection with our assessment of the realizability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of our deferred tax assets will not be realized. In the event it is more likely than not that some portion or all of our deferred taxes will not be realized, such assets are reduced by a valuation allowance. Future increases to our valuation allowance are possible if our estimates and assumptions (particularly as they relate to downward revisions of our long-term commodity price forecast) are revised such that they reduce estimates of future taxable income during the carryforward period.
9
. Inventories
Liquid hydrocarbons, natural gas and bitumen are recorded at weighted average cost and carried at the lower of cost or market value. Supplies and other items consist principally of tubular goods and equipment which are valued at weighted average cost and reviewed periodically for obsolescence or impairment when market conditions indicate.
|
|
March 31,
|
December 31,
|
|||||
|
(In millions)
|
2016
|
2015
|
|||||
|
Liquid hydrocarbons, natural gas and bitumen
|
$
|
33
|
|
$
|
35
|
|
|
|
Supplies and other items
|
273
|
|
278
|
|
|||
|
Inventories, at cost
|
$
|
306
|
|
$
|
313
|
|
|
10
. Property, Plant and Equipment, net of Accumulated Depreciation, Depletion and Amortization
|
|
March 31,
|
December 31,
|
|||||
|
(In millions)
|
2016
|
2015
|
|||||
|
North America E&P
|
$
|
14,953
|
|
$
|
15,226
|
|
|
|
International E&P
|
2,521
|
|
2,533
|
|
|||
|
Oil Sands Mining
|
9,148
|
|
9,197
|
|
|||
|
Corporate
|
115
|
|
105
|
|
|||
|
Net property, plant and equipment
|
$
|
26,737
|
|
|
$
|
27,061
|
|
Our Libya operations continue to be impacted by civil unrest. Operations were interrupted in mid-2013 as a result of the shutdown of the Es Sider crude oil terminal, and although temporarily re-opened during the second half of 2014, production remains shut-in. Considerable uncertainty remains around the timing of future production and sales levels.
As of
March 31, 2016
, our net property, plant and equipment investment in Libya is
$776 million
, and total proved reserves (unaudited) in Libya as of December 31, 2015 are
235 million
barrels of oil equivalent ("mmboe"). We and our partners in the Waha concessions continue to assess the situation and the condition of our assets in Libya. Our periodic assessment of the carrying value of our net property, plant and equipment in Libya specifically considers the net investment in the assets, the duration of our concessions and the reserves anticipated to be recoverable in future periods. The undiscounted cash flows related to our Libya assets continue to exceed the carrying value of
$776 million
by a material amount.
10
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
Exploratory well costs capitalized greater than one year after completion of drilling were
$120 million
and
$85 million
as of
March 31, 2016
and
December 31, 2015
. The
$35 million
increase primarily relates to the Alba Block Sub Area B offshore Equatorial Guinea where the Rodo well reached total depth in the first quarter of 2015. We have since completed a seismic feasibility study and continue to finalize next steps in the Alba Block Sub Area B exploration program.
11
. Fair Value Measurements
Fair Values - Recurring
The following tables present assets and liabilities accounted for at fair value on a recurring basis as of
March 31, 2016
and
December 31, 2015
by fair value hierarchy level.
|
March 31, 2016
|
|||||||||||||||
|
(In millions)
|
Level 1
|
Level 2
|
Level 3
|
Total
|
|||||||||||
|
Derivative instruments, assets
|
|||||||||||||||
|
Commodity
(a)
|
$
|
—
|
|
$
|
51
|
|
$
|
—
|
|
$
|
51
|
|
|||
|
Interest rate
|
—
|
|
12
|
|
—
|
|
12
|
|
|||||||
|
Derivative instruments, assets
|
$
|
—
|
|
$
|
63
|
|
$
|
—
|
|
$
|
63
|
|
|||
|
Derivative instruments, liabilities
|
|||||||||||||||
|
Commodity
(a)
|
$
|
—
|
|
$
|
24
|
|
$
|
—
|
|
$
|
24
|
|
|||
|
Derivative instruments, liabilities
|
$
|
—
|
|
$
|
24
|
|
$
|
—
|
|
$
|
24
|
|
|||
|
(a)
|
Derivative instruments are recorded on a net basis in the company's balance sheet (see Note
12
).
|
|
|
December 31, 2015
|
||||||||||||||
|
(In millions)
|
Level 1
|
Level 2
|
Level 3
|
Total
|
|||||||||||
|
Derivative instruments, assets
|
|||||||||||||||
|
Commodity
(a)
|
$
|
—
|
|
$
|
51
|
|
$
|
—
|
|
$
|
51
|
|
|||
|
Interest rate
|
$
|
—
|
|
$
|
8
|
|
$
|
—
|
|
$
|
8
|
|
|||
|
Derivative instruments, assets
|
$
|
—
|
|
$
|
59
|
|
$
|
—
|
|
$
|
59
|
|
|||
|
Derivative instruments, liabilities
|
|||||||||||||||
|
Commodity
(a)
|
$
|
—
|
|
$
|
1
|
|
$
|
—
|
|
$
|
1
|
|
|||
|
Derivative instruments, liabilities
|
$
|
—
|
|
$
|
1
|
|
$
|
—
|
|
$
|
1
|
|
|||
|
(a)
|
Derivative instruments are recorded on a net basis in the company's balance sheet (see Note
12
).
|
Commodity derivatives include three-way collars, extendable three-way collars, call options, swaps and swaptions. These instruments are measured at fair value using either the Black-Scholes Model or the Black Model. Inputs to both models include prices, interest rates, and implied volatility. The inputs to these models are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.
Interest rate swaps are measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs. See Note
12
for additional discussion of the types of derivative instruments we use.
Fair Values – Goodwill
Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. We estimate the fair value of our International E&P reporting unit using a combination of market and income approaches. The market approach referenced observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value, and valuation multiples of us and our peers for the investor analyst community. The income approach utilized discounted cash flows, which were based on forecasted assumptions. Key assumptions to the income approach include future liquid hydrocarbon and natural gas pricing, estimated quantities of liquid hydrocarbons and natural gas proved and probable reserves, estimated timing of production, discount rates, future capital requirements and operating expenses and tax rates. The assumptions used in the income approach are consistent with those that management uses to make business decisions. These valuations methodologies represent Level 3 fair value measurements. A triggering event related to price declines in our common stock required us to reassess our goodwill
11
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
for impairment as of March 31, 2016. Based on the results of this assessment, we concluded no impairment was required. While the fair value of our International E&P reporting unit exceeded book value, subsequent commodity price and/or common stock declines may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.
Fair Values – Financial Instruments
Our current assets and liabilities include financial instruments, the most significant of which are receivables, long-term debt and payables. We believe the carrying values of our receivables and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our credit rating, and (3) our historical incurrence of and expected future insignificant bad debt expense, which includes an evaluation of counterparty credit risk.
The following table summarizes financial instruments, excluding receivables, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at
March 31, 2016
and
December 31, 2015
.
|
March 31, 2016
|
December 31, 2015
|
||||||||||||||
|
|
Fair
|
Carrying
|
Fair
|
Carrying
|
|||||||||||
|
(In millions)
|
Value
|
Amount
|
Value
|
Amount
|
|||||||||||
|
Financial assets
|
|
|
|
|
|||||||||||
|
Other noncurrent assets
|
$
|
115
|
|
$
|
120
|
|
$
|
104
|
|
$
|
118
|
|
|||
|
Total financial assets
|
$
|
115
|
|
$
|
120
|
|
$
|
104
|
|
$
|
118
|
|
|||
|
Financial liabilities
|
|
|
|
|
|
|
|
|
|||||||
|
Other current liabilities
|
$
|
34
|
|
$
|
33
|
|
$
|
34
|
|
$
|
33
|
|
|||
|
Long-term debt, including current portion
(a)
|
6,575
|
|
7,291
|
|
6,723
|
|
7,291
|
|
|||||||
|
Deferred credits and other liabilities
|
104
|
|
105
|
|
97
|
|
95
|
|
|||||||
|
Total financial liabilities
|
$
|
6,713
|
|
$
|
7,429
|
|
$
|
6,854
|
|
$
|
7,419
|
|
|||
(a)
Excludes capital leases, debt issuance costs and interest rate swap adjustments.
Fair values of our financial assets included in other noncurrent assets, and of our financial liabilities included in other current liabilities and deferred credits and other liabilities, are measured using an income approach and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value.
Most of our long-term debt instruments are publicly-traded. A market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is used to measure the fair value of such debt. The fair value of our debt that is not publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.
12
. Derivatives
For further information regarding the fair value measurement of derivative instruments, see Note
11
. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts where they appear on the consolidated balance sheets.
12
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
|
March 31, 2016
|
|||||||||||||
|
(In millions)
|
Asset
|
Liability
|
Net Asset
|
Balance Sheet Location
|
|||||||||
|
Fair Value Hedges
|
|||||||||||||
|
Interest rate
|
$
|
12
|
|
$
|
—
|
|
$
|
12
|
|
Other noncurrent assets
|
|||
|
Total Designated Hedges
|
$
|
12
|
|
$
|
—
|
|
$
|
12
|
|
||||
|
Not Designated as Hedges
|
|||||||||||||
|
Commodity
|
$
|
51
|
|
$
|
7
|
|
$
|
44
|
|
Other current assets
|
|||
|
Total Not Designated as Hedges
|
$
|
51
|
|
$
|
7
|
|
$
|
44
|
|
||||
|
Total
|
$
|
63
|
|
|
$
|
7
|
|
|
$
|
56
|
|
||
|
March 31, 2016
|
|||||||||||||
|
(In millions)
|
Asset
|
Liability
|
Net Liability
|
Balance Sheet Location
|
|||||||||
|
Not Designated as Hedges
|
|||||||||||||
|
Commodity
|
$
|
—
|
|
$
|
17
|
|
$
|
17
|
|
Deferred credits and other liabilities
|
|||
|
Total Not Designated as Hedges
|
$
|
—
|
|
$
|
17
|
|
$
|
17
|
|
||||
|
Total
|
$
|
—
|
|
$
|
17
|
|
$
|
17
|
|
||||
|
December 31, 2015
|
|||||||||||||
|
(In millions)
|
Asset
|
Liability
|
Net Asset
|
Balance Sheet Location
|
|||||||||
|
Fair Value Hedges
|
|||||||||||||
|
Interest rate
|
$
|
8
|
|
$
|
—
|
|
$
|
8
|
|
Other noncurrent assets
|
|||
|
Total Designated Hedges
|
$
|
8
|
|
$
|
—
|
|
$
|
8
|
|
||||
|
Not Designated as Hedges
|
|||||||||||||
|
Commodity
|
$
|
51
|
|
$
|
1
|
|
$
|
50
|
|
Other current assets
|
|||
|
Total Not Designated as Hedges
|
$
|
51
|
|
$
|
1
|
|
$
|
50
|
|
||||
|
Total
|
$
|
59
|
|
$
|
1
|
|
$
|
58
|
|
||||
Derivatives Designated as Fair Value Hedges
The following table presents, by maturity date, information about our interest rate swap agreements, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.
|
March 31, 2016
|
December 31, 2015
|
||||||||||
|
Aggregate Notional Amount
|
Weighted Average, LIBOR-Based,
|
Aggregate Notional Amount
|
Weighted Average, LIBOR-Based,
|
||||||||
|
Maturity Dates
|
(in millions)
|
Floating Rate
|
(in millions)
|
Floating Rate
|
|||||||
|
October 1, 2017
|
$
|
600
|
|
4.92
|
%
|
$
|
600
|
|
4.73
|
%
|
|
|
March 15, 2018
|
$
|
300
|
|
4.77
|
%
|
$
|
300
|
|
4.66
|
%
|
|
13
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
The pretax effects of derivative instruments designated as hedges of fair value in our consolidated statements of income are summarized in the table below. There is no ineffectiveness related to fair value hedges.
|
|
|
Gain (Loss)
|
|||||||
|
Three Months Ended March 31,
|
|||||||||
|
(In millions)
|
Income Statement Location
|
2016
|
2015
|
||||||
|
Derivative
|
|
|
|
||||||
|
Interest rate
|
Net interest and other
|
$
|
4
|
|
$
|
5
|
|
||
|
Hedged Item
|
|
|
|
|
|
||||
|
Long-term debt
|
Net interest and other
|
$
|
(4
|
)
|
$
|
(5
|
)
|
||
Derivatives not Designated as Hedges
During 2015 and the first quarter of 2016, we entered into multiple crude oil and natural gas derivatives indexed to NYMEX WTI and Henry Hub related to a portion of our forecasted North America E&P sales through December 2017. These commodity derivatives consist of three-way collars, extendable three-way collars, call options, swaps, and swaptions. Three-way collars consist of a sold call (ceiling), a purchased put (floor) and a sold put. The ceiling price is the maximum we will receive for the contract volumes, the floor is the minimum price we will receive, unless the market price falls below the sold put strike price. In this case, we receive the NYMEX WTI/Henry Hub price plus the difference between the floor and the sold put price. These commodity derivatives were not designated as hedges. The following table sets forth outstanding derivative contracts as of March 31, 2016 and the weighted average prices for those contracts:
|
Crude Oil
(a)
|
||||
|
2016
|
Year Ending December 31,
|
|||
|
Second Quarter
|
Third Quarter
|
Fourth Quarter
|
2017
|
|
|
Three-Way Collars
(b)
|
||||
|
Volume (Bbls/day)
|
39,000
|
37,000
|
37,000
|
—
|
|
Price per Bbl:
|
||||
|
Ceiling
|
$55.47
|
$54.52
|
$54.52
|
—
|
|
Floor
|
$51.56
|
$50.83
|
$50.83
|
—
|
|
Sold put
|
$41.67
|
$41.22
|
$41.22
|
—
|
|
Options
(c)
|
||||
|
Volume (Bbls/day)
|
10,000
|
10,000
|
10,000
|
25,000
|
|
Price per Bbl
|
$72.39
|
$72.39
|
$72.39
|
$60.67
|
|
Swaps
|
||||
|
Volume (Bbls/day)
|
25,000
|
—
|
—
|
—
|
|
Price per Bbl
|
$39.25
|
—
|
—
|
—
|
(a)
Subsequent to March 31, 2016, we entered into
10,000
Bbls/day of two-way collars for July - December 2016 with a ceiling price of
$50.00
and a floor price of $
41.55
. We also entered into
10,000
Bbls/day of 2016 three-way collars for May - December 2016 with a ceiling price of
$58.51
, a floor price of
$48.00
, and a sold put price of
$40.00
, traded in conjunction with sold call options of
10,000
Bbls/day for 2017 at
$65.00
.
|
(b)
|
A counterparty has the option, exercisable on June 30, 2016, to extend three-way collars for
2,000
Bbls/day through the remainder of 2016 at a ceiling of
$73.13
, floor of
$65.00
and sold put of
$50.00
.
|
|
(c)
|
Call options settle monthly.
|
14
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
|
Natural Gas
(a)
|
||||
|
2016
|
Year Ending December 31,
|
|||
|
Second Quarter
|
Third Quarter
|
Fourth Quarter
|
2017
|
|
|
Three-Way Collars
(b)
|
||||
|
Volume (MMBtu/day)
|
20,000
|
20,000
|
20,000
|
20,000
|
|
Price per MMBtu
|
||||
|
Ceiling
|
$2.93
|
$2.93
|
$2.93
|
$3.07
|
|
Floor
|
$2.50
|
$2.50
|
$2.50
|
$2.75
|
|
Sold put
|
$2.00
|
$2.00
|
$2.00
|
$2.25
|
|
(a)
|
Subsequent to March 31, 2016, we entered into
20,000
MMBtu/day of 2017 three-way collars with a ceiling price of
$3.50
, a floor price of
$2.75
, and a sold put price of
$2.25
.
|
|
(b)
|
Counterparty has the option to execute fixed-price swaps (swaptions) at a weighted average price of
$2.93
per MMBtu indexed to NYMEX Henry Hub, which is exercisable on December 22, 2016. If counterparty exercises, the term of the fixed-price swaps would be for the calendar year 2017 and, if all such options are exercised,
20,000
MMBtu per day.
|
The impact of these commodity derivative instruments appears in sales and other operating revenues in our consolidated statements of income and was a net loss of
$2 million
and net gain of
$26 million
in the
first quarter
s of
2016
and 2015, respectively.
13
. Incentive Based Compensation
Stock options, restricted stock awards and restricted stock units
The following table presents a summary of activity for the
first three months of 2016
:
|
|
Stock Options
|
Restricted Stock Awards & Units
|
|||||||||||
|
Number of
Shares
|
Weighted
Average
Exercise Price
|
Awards
|
Weighted
Average Grant
Date Fair Value
|
||||||||||
|
Outstanding at December 31, 2015
|
12,665,419
|
|
|
|
$29.97
|
|
4,017,344
|
|
|
$30.76
|
|
||
|
Granted
|
1,680,000
|
|
(a)
|
|
$7.22
|
|
5,230,708
|
|
|
$7.91
|
|
||
|
Options Exercised/Stock Vested
|
—
|
|
—
|
|
(44,096
|
)
|
|
$32.01
|
|
||||
|
Canceled
|
(181,681
|
)
|
|
$29.69
|
|
(220,614
|
)
|
|
$30.00
|
|
|||
|
Outstanding at March 31, 2016
|
14,163,738
|
|
|
|
$27.27
|
|
8,983,342
|
|
|
$17.47
|
|
||
(a)
The weighted average grant date fair value of stock option awards granted was
$1.97
per share.
Stock-based performance unit awards
During the
first three months of 2016
, we granted
1,205,517
stock-based performance units to certain officers. The grant date fair value per unit was
$3.72
.
14
. Debt
Revolving Credit Facility
As of
March 31, 2016
, we had no borrowings against our revolving credit facility (the "Credit Facility"), as described below.
In March 2016, we increased our
$3.0 billion
unsecured Credit Facility by
$300 million
to a total of
$3.3 billion
. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the increase.
The Credit Facility includes a covenant requiring that our ratio of total debt to total capitalization not exceed
65%
as of the last day of each fiscal quarter. If an event of default occurs, the lenders holding more than half of the commitments may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and
15
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
the cash collateralization of all outstanding letters of credit under the Credit Facility. As of
March 31, 2016
, we were in compliance with this covenant with a debt-to-capitalization ratio of
27%
.
15
. Reclassifications Out of Accumulated Other Comprehensive Loss
The following table presents a summary of amounts reclassified from accumulated other comprehensive loss:
|
Three Months Ended March 31,
|
|||||||||
|
(In millions)
|
2016
|
2015
|
Income Statement Line
|
||||||
|
Postretirement and postemployment plans
|
|||||||||
|
Amortization of actuarial loss
|
$
|
(3
|
)
|
$
|
(7
|
)
|
General and administrative
|
||
|
Net settlement loss
|
(48
|
)
|
(17
|
)
|
General and administrative
|
||||
|
Net curtailment gain (loss)
|
—
|
|
5
|
|
General and administrative
|
||||
|
(51
|
)
|
(19
|
)
|
Income (loss) from operations
|
|||||
|
19
|
|
7
|
|
Provision (benefit) for income taxes
|
|||||
|
Total reclassifications to expense
|
$
|
(32
|
)
|
$
|
(12
|
)
|
Net income (loss)
|
||
16
. Stockholder's Equity
In March 2016, we issued
166,750,000
shares of our common stock, par value
$1
per share, at a price of
$7.65
per share, excluding underwriting discounts and commissions, for net proceeds of
$1,232 million
. The proceeds will be used to strengthen our balance sheet and for general corporate purposes, including funding a portion of our Capital Program.
17
. Supplemental Cash Flow Information
|
|
Three Months Ended March 31,
|
||||||
|
(In millions)
|
2016
|
2015
|
|||||
|
Net cash (used in) operating activities:
|
|
|
|||||
|
Interest paid (net of amounts capitalized)
|
$
|
(87
|
)
|
$
|
(55
|
)
|
|
|
Income taxes paid to taxing authorities
|
(15
|
)
|
(47
|
)
|
|||
|
Noncash investing activities:
|
|
|
|
|
|||
|
Asset retirement cost increase
|
$
|
2
|
|
$
|
21
|
|
|
|
Asset retirement obligations assumed by buyer
|
54
|
|
—
|
|
|||
18
. Commitments and Contingencies
We are a defendant in a number of legal and administrative proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims, tax disputes and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.
19. Subsequent Event
In September 2015, we announced our intention to scale back our conventional exploration program, with future exploration investment focused on fulfilling our existing commitments in the Gulf of Mexico and Gabon. In April 2016, we made the decision not to drill any of our remaining Gulf of Mexico undeveloped leases. As a result, we expect to record a non-cash impairment between
$140 million
and
$150 million
in the second quarter of 2016. We retain our existing deepwater drilling rig commitment, in which we have approximately 200 days of contract term remaining.
16
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the preceding consolidated financial statements and notes in Item 1.
Executive Overview
We are an independent global exploration and production company based in Houston, Texas with operations in North America, Europe and Africa and a focus on U.S. unconventional resource plays. Total proved reserves were 2.2 billion boe at December 31, 2015 and total assets were
$33 billion
at
March 31, 2016
.
Our significant strategic actions and financial results include the following:
|
•
|
Continued to strengthen the balance sheet
|
|
◦
|
Raised net $1.2 billion from equity offering in the first quarter of 2016
|
|
◦
|
At the end of the first quarter of 2016, we had $5.4 billion of liquidity, comprised of $2.1 billion in cash and an undrawn $3.3 billion revolving credit facility
|
|
◦
|
Announced or closed $1.3 billion of non-core asset sales since August 2015, surpassing our target of $750 million to $1 billion. The largest component of this total was the $950 million non-core asset sales announced in April 2016 which consisted of:
|
|
▪
|
Wyoming upstream and midstream assets of $870 million, before closing adjustments
|
|
▪
|
Shenandoah discovery in the Gulf of Mexico (10% outside operated working interest); Piceance operated natural gas assets in Colorado; certain undeveloped acreage in West Texas for a combined total of approximately $80 million, before closing adjustments
|
|
◦
|
Additions to property, plant and equipment, including accruals, of
$359 million
for the first quarter of 2016, down 67% compared to the year-ago quarter, reflecting continued capital discipline
|
|
◦
|
Executed additional commodity derivative instruments during the first quarter to reduce commodity price uncertainty for North America E&P crude oil and natural gas
|
|
◦
|
Reduced production expenses per boe in the
first quarter
of 2016 compared to the same period last year
|
|
▪
|
North America E&P - 22% reduction to
$6.17
per boe
|
|
▪
|
Oil Sands Mining - 17% reduction to
$28.80
per boe
|
|
◦
|
Cash-adjusted debt-to-capital ratio of
21%
at
March 31, 2016
, as compared with
25%
at December 31, 2015
|
|
•
|
Financial results
|
|
◦
|
Net loss per share of
$0.56
in the
first quarter
of
2016
as compared to net loss per share of
$0.41
in the same period last year
|
Outlook
Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows and the amount of capital available to reinvest into our business. We remain on track to achieve our objective of spending within our cash flows in 2016, inclusive of the non-core asset sales recently announced. We will continue to strengthen the balance sheet, evaluate our portfolio for strategic opportunities, adjust our Capital Program as necessary, and drive the fundamentals of expense management.
17
Exploration Update
In September 2015, we announced our intention to scale back our conventional exploration program, with future exploration investment focused on fulfilling our existing commitments in the Gulf of Mexico and Gabon. In April 2016, we made the decision not to drill any of our remaining Gulf of Mexico undeveloped leases. As a result, we expect to record a non-cash impairment between $140 million and $150 million in the second quarter of 2016. We retain our existing deepwater drilling rig commitment, in which we have approximately 200 days of contract term remaining. We are currently evaluating our options related to this commitment. We expect this rig to return to us late in the third quarter or early fourth quarter of 2016.
Operations
The following table presents a summary of our sales volumes for each of our segments. Refer to the Results of Operations for a price-volume analysis for each of the segments.
|
Three Months Ended March 31,
|
|||||
|
Net Sales Volumes
|
2016
|
2015
|
Increase
(Decrease) |
||
|
North America E&P
(mboed)
|
239
|
283
|
(16)%
|
||
|
International E&P
(mboed)
|
96
|
116
|
(17)%
|
||
|
Oil Sands Mining
(mbbld)
(a)
|
59
|
60
|
(2)%
|
||
|
Total
(mboed)
|
394
|
459
|
(14)%
|
||
North America E&P
Net sales volumes in the segment were lower in the first quarter of 2016 primarily as a result of decreased drilling and completion activity resulting in fewer wells brought to sales as well as 2015 dispositions of certain non-core assets (Gulf of Mexico and East Texas, North Louisiana and Wilburton, Oklahoma). The following tables provide details regarding net sales volumes, sales mix and operational drilling activity for our significant operations within this segment:
|
Three Months Ended March 31,
|
|||||
|
Net Sales Volumes
|
2016
|
2015
|
Increase
(Decrease) |
||
|
Equivalent Barrels
(mboed)
|
|||||
|
Eagle Ford
|
121
|
147
|
(18)%
|
||
|
Oklahoma Resource Basins
|
27
|
25
|
8%
|
||
|
Bakken
|
57
|
57
|
—
|
||
|
Other North America
(a)
|
34
|
54
|
(37)%
|
||
|
Total North America E&P
|
239
|
283
|
(16)%
|
||
|
Three Months Ended March 31, 2016
|
|||||
|
Sales Mix - U.S. Resource Plays
|
Crude oil and condensate
|
Natural gas liquids
|
Natural gas
|
||
|
Eagle Ford
|
58%
|
21%
|
21%
|
||
|
Oklahoma Resource Basins
|
19%
|
26%
|
55%
|
||
|
Bakken
|
82%
|
11%
|
7%
|
||
|
Three Months Ended March 31,
|
|||
|
2016
|
2015
|
||
|
Gross Operated
|
|||
|
Eagle Ford:
|
|||
|
Wells drilled to total depth
|
58
|
88
|
|
|
Wells brought to sales
|
50
|
91
|
|
|
Oklahoma Resource Basins:
|
|||
|
Wells drilled to total depth
|
5
|
8
|
|
|
Wells brought to sales
|
3
|
5
|
|
|
Bakken:
|
|||
|
Wells drilled to total depth
|
3
|
20
|
|
|
Wells brought to sales
|
6
|
24
|
|
|
•
|
Eagle Ford
– Of the 50 gross operated wells brought to sales during the first quarter of 2016, 23 were Lower Eagle Ford, 19 were Upper Eagle Ford and 8 were Austin Chalk. Our average time to drill an Eagle Ford well in the
first quarter
2016
, spud-to-total depth, decreased to 8 days from 12 days in the same quarter last year as efficiency gains in drilling continued. Wells were drilled at an average rate of 2,300 feet per day and the top-performing Eagle Ford rigs drilled four wells in excess of 3,300 feet per day.
|
|
•
|
Oklahoma Resource Basins
– In the first quarter of 2016, we continued our focus on leasehold protection and delineation and brought 3 gross operated wells to sales, of which one was in the SCOOP Woodford, one in the SCOOP Springer and one in the STACK Meramec. We also participated in 7 outside-operated wells during the first quarter of 2016 that were focused in SCOOP and STACK.
|
|
•
|
Bakken
– The 6 gross operated wells brought to sales in the first quarter of 2016 were in the greater Hector area, of which 4 were in Middle Bakken and 2 in Three Forks. Our average time to drill a Bakken well in the first quarter of 2016, spud-to-total depth, decreased to 12 days from 17 days in the first quarter of 2015. We released the remaining drilling rig in February and expect reduced completions activity during the second quarter.
|
|
•
|
Other North America
– Net sales volumes declined in the first quarter of 2016 primarily due to the 2015 sales of the non-core assets in the Gulf of Mexico and East Texas, North Louisiana and Wilburton, Oklahoma. Additionally, development work continues in the Gunflint field located in Mississippi Canyon. First oil is expected in the second half of 2016 after the completion of work at a third party facility. We hold an 18% non-operated working interest in the Gunflint field.
|
International E&P
Net sales volumes in the segment were lower in the first quarter of 2016 primarily as a result of planned downtime in E.G. and repairs at Brae Alpha in the U.K. The following table provides details regarding net sales volumes for our significant operations within this segment.
|
Three Months Ended March 31,
|
|||||
|
Net Sales Volumes
|
2016
|
2015
|
Increase
(Decrease) |
||
|
Equivalent Barrels
(mboed)
|
|||||
|
Equatorial Guinea
|
84
|
97
|
(13)%
|
||
|
United Kingdom
(a)
|
12
|
19
|
(37)%
|
||
|
Total International E&P
|
96
|
116
|
(17)%
|
||
|
Equity Method Investees
|
|||||
|
LNG
(mtd)
|
4,322
|
6,275
|
(31)%
|
||
|
Methanol
(mtd)
|
1,280
|
884
|
45%
|
||
|
Condensate & LPG
(boed)
|
10,208
|
13,223
|
(23)%
|
||
|
(a)
|
Includes natural gas acquired for injection and subsequent resale of
5
mmcfd and
10
mmcfd for the
first quarter
s of
2016
and
2015
.
|
|
•
|
Equatorial Guinea
– First quarter 2016 net sales were reduced compared to prior year quarter due to planned downtime associated with the installation of the Alba compression jacket and topsides, and planned maintenance activities in the onshore plants. This planned maintenance was successfully completed under budget and ahead of schedule. The ongoing Alba field compression project, designed to maintain the production plateau for an additional two years and extend field life up to eight years, remains on schedule with first production mid-year.
|
19
|
•
|
United Kingdom
– Net sales volumes in first quarter 2016 were lower as a result of repairs at Brae Alpha which was shut-in throughout the quarter following a process pipe failure in late 2015, partially offset by improved reliability from the outside-operated Foinaven field. Full production from Brae Alpha resumed in late April.
|
|
•
|
Libya
– Due to continued civil unrest, there were no liftings during the quarter. Considerable uncertainty remains around the timing of future production and sales levels.
|
Oil Sands Mining
Our net synthetic crude oil sales volumes were
59
mbbld
first quarter of
2016
compared to
60
mbbld in the same period of
2015
. Planned maintenance activities began ahead of schedule in mid-March at the base upgrader and the Jackpine mine which will impact production in the second quarter. In addition, in early May our operations at the Muskeg River and Jackpine mines have been suspended to support emergency response efforts related to the Fort McMurray area wildfires. The mines are approximately 60 miles north of the wildfires and not currently threatened by fire. We hold a 20% non-operated working interest in the Athabasca Oil Sands Project.
20
Market Conditions
Prevailing prices for the crude oil, NGLs and natural gas that we produce significantly impact our revenues and cash flows. The benchmark prices for crude oil, NGLs and natural gas were lower in the
first quarter of
2016
as compared to the same period in
2015
; as a result, we experienced declines in our price realizations associated with those benchmarks. Additional detail on market conditions, including our average price realizations and benchmarks for crude oil, NGLs and natural gas relative to our operating segments, follows.
North America E&P
The following table presents our average price realizations and the related benchmarks for crude oil, NGLs and natural gas for the
first quarter of
2016
and
2015
.
|
Three Months Ended March 31,
|
||||||||||
|
2016
|
2015
|
Increase (Decrease)
|
||||||||
|
Average Price Realizations
(a)
|
||||||||||
|
Crude Oil and Condensate
(per bbl)
(b)
|
$28.21
|
$41.75
|
(32
|
)%
|
||||||
|
Natural Gas Liquids
(per bbl)
|
8.12
|
|
14.43
|
|
(44
|
)%
|
||||
|
Total Liquid Hydrocarbons
(per bbl)
|
24.00
|
|
36.92
|
|
(35
|
)%
|
||||
|
Natural Gas
(per mcf)
|
2.02
|
|
3.01
|
|
(33
|
)%
|
||||
|
Benchmarks
|
||||||||||
|
WTI crude oil
(per bbl)
|
|
$33.63
|
|
|
$48.58
|
|
(31
|
)%
|
||
|
LLS crude oil
(per bbl)
|
35.33
|
|
52.84
|
|
(33
|
)%
|
||||
|
Mont Belvieu NGLs
(per bbl)
(c)
|
13.95
|
|
18.39
|
|
(24
|
)%
|
||||
|
Henry Hub natural gas
(per mmbtu)
|
2.09
|
|
2.98
|
|
(30
|
)%
|
||||
|
(a)
|
Excludes gains or losses on commodity derivative instruments.
|
|
(b)
|
Inclusion of realized gains on crude oil derivative instruments would have increased average realizations by
$1.64
per bbl and
$0.21
per bbl for the
first quarter
2016 and 2015.
|
|
(c)
|
Bloomberg Finance LLP: Y-grade Mix NGL of 50% ethane, 25% propane, 10% butane, 5% isobutane and 10% natural gasoline.
|
Crude oil and condensate
– Our crude oil and condensate price realizations may differ from the benchmark due to the quality and location of the product.
Natural gas liquids
– The majority of our NGL volumes are sold at reference to Mont Belvieu prices.
Natural gas
–
A significant portion of our natural gas production in the U.S. is sold at bid-week prices, or first-of-month indices relative to our specific producing areas.
International E&P
The following table presents our average price realizations and the related benchmark for crude oil, NGLs, and natural gas for the
first quarter of
2016
and
2015
.
|
Three Months Ended March 31,
|
||||||||||
|
2016
|
2015
|
Increase
(Decrease) |
||||||||
|
Average Price Realizations
|
||||||||||
|
Crude Oil and Condensate (
per bbl
)
|
$30.95
|
$48.87
|
(37
|
)%
|
||||||
|
Natural Gas Liquids (
per bbl
)
|
2.20
|
|
3.46
|
|
(36
|
)%
|
||||
|
Liquid Hydrocarbons (
per bbl
)
|
22.66
|
|
37.31
|
|
(39
|
)%
|
||||
|
Natural Gas (
per mcf
)
|
0.60
|
|
0.78
|
|
(23
|
)%
|
||||
|
Benchmark
|
|
|
||||||||
|
Brent (Europe) crude oil (
per bbl
)
(a)
|
|
$33.70
|
|
|
$53.92
|
|
(38
|
)%
|
||
|
(a)
|
Average of monthly prices obtained from EIA website.
|
Liquid hydrocarbons
– Our U.K. liquid hydrocarbon production is generally sold in relation to the Brent crude benchmark. Our production from Equatorial Guinea is condensate, which receives lower prices than crude oil.
21
Our NGL and natural gas sales in the International E&P segment originate primarily from our E.G. operations and are sold to our equity method investees under fixed-price, term contracts; therefore, our reported average realized prices for NGLs and natural gas will not fully track market price movements. The equity affiliates then utilize, process and sell the NGLs and natural gas at market prices, with our share of their income/loss reflected in the Income from equity method investments line item on the Consolidated Statements of Income.
Oil Sands Mining
The Oil Sands Mining segment produces and sells various qualities of synthetic crude oil. Output mix can be impacted by operational reliability or planned unit outages at the mines or upgrader. Sales prices for roughly two-thirds of the normal output mix have historically tracked movements in WTI and one-third have historically tracked movements in the Canadian heavy crude oil marker, primarily WCS.
The following table presents our average price realizations and the related benchmarks for the
first quarter of
2016
and
2015
.
|
Three Months Ended March 31,
|
||||||||||
|
2016
|
2015
|
Increase (Decrease)
|
||||||||
|
Average Price Realizations
|
||||||||||
|
Synthetic Crude Oil
(per bbl)
|
|
$26.41
|
|
|
$40.37
|
|
(35
|
%)
|
||
|
Benchmarks
|
||||||||||
|
WTI crude oil
(per bbl)
|
|
$33.63
|
|
|
$48.58
|
|
(31
|
%)
|
||
|
WCS crude oil
(per bbl)
(a)
|
19.21
|
|
33.90
|
|
(43
|
%)
|
||||
|
(a)
|
Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.
|
22
Results of Operations
Three Months Ended March 31, 2016
vs.
Three Months Ended March 31, 2015
Sales and other operating revenues, including related party
are presented by segment in the table below:
|
|
Three Months Ended March 31,
|
||||||
|
(In millions)
|
2016
|
2015
|
|||||
|
Sales and other operating revenues, including related party
|
|||||||
|
North America E&P
|
$
|
493
|
|
$
|
850
|
|
|
|
International E&P
|
96
|
|
182
|
|
|||
|
Oil Sands Mining
|
148
|
|
225
|
|
|||
|
Segment sales and other operating revenues, including related party
|
$
|
737
|
|
$
|
1,257
|
|
|
|
Unrealized (loss) gain on crude oil derivative instruments
|
(23
|
)
|
23
|
|
|||
|
Sales and other operating revenues, including related party
|
$
|
714
|
|
$
|
1,280
|
|
|
Below is a price/volume analysis for each segment. Refer to the preceding Operations and Market Conditions sections for additional detail related to our net sales volumes and average price realizations.
|
Three Months Ended
|
Increase (Decrease) Related to
|
Three Months Ended
|
||||||||||||||
|
(In millions)
|
March 31, 2015
|
Price Realizations
|
Net Sales Volumes
|
March 31, 2016
|
||||||||||||
|
North America E&P Price-Volume Analysis
|
||||||||||||||||
|
Liquid hydrocarbons
|
$
|
741
|
|
$
|
(220
|
)
|
$
|
(113
|
)
|
$
|
408
|
|
||||
|
Natural gas
|
97
|
|
(29
|
)
|
(11
|
)
|
57
|
|
||||||||
|
Realized gain on crude oil
|
||||||||||||||||
|
derivative instruments
|
3
|
|
19
|
|
|
|
22
|
|
||||||||
|
Other sales
|
9
|
|
|
|
|
|
6
|
|
||||||||
|
Total
|
$
|
850
|
|
$
|
493
|
|
||||||||||
|
International E&P Price-Volume Analysis
|
||||||||||||||||
|
Liquid hydrocarbons
|
$
|
139
|
|
$
|
(43
|
)
|
$
|
(30
|
)
|
$
|
66
|
|
||||
|
Natural gas
|
32
|
|
(6
|
)
|
(5
|
)
|
21
|
|
||||||||
|
Other sales
|
11
|
|
9
|
|
||||||||||||
|
Total
|
$
|
182
|
|
$
|
96
|
|
||||||||||
|
Oil Sands Mining Price-Volume Analysis
|
||||||||||||||||
|
Synthetic crude oil
|
$
|
217
|
|
$
|
(74
|
)
|
$
|
—
|
|
$
|
143
|
|
||||
|
Other sales
|
8
|
|
|
|
|
|
5
|
|
||||||||
|
Total
|
$
|
225
|
|
$
|
148
|
|
||||||||||
Marketing revenues
decreased
$146 million
in the
first quarter of 2016
from the comparable prior-year period. Marketing activities include the purchase of commodities from third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points. Since the volume of marketing activity is based on market dynamics, it can fluctuate from period to period. The decreases are related primarily to lower marketed volumes in North America, which were further compounded by a lower commodity price environment.
Income from equity method investments
decreased
$
22 million
in the
first quarter of 2016
from the comparable
2015
period. The decrease is primarily due to lower net sales volumes as a result of planned downtime at E.G. as a result of the Alba field compression project which impacted our equity method plants. Also impacting the quarter were lower price realizations for LPG at our Alba plant and lower methanol prices at our AMPCO methanol facility.
Net loss on disposal of assets
in the
first quarter of 2016
was related to the sale of non-core assets. See Note
5
to the consolidated financial statements for information about dispositions.
Production expenses
decreased
$116 million
. North America E&P declined $68 million primarily due to lower operational, maintenance and labor costs, coupled with the 2015 disposition of certain producing Gulf of Mexico assets. International E&P declined $14 million primarily as a result of lower operational costs in Libya and lower costs in the U.K. associated with lower net sales volumes, which was offset by higher planned maintenance costs in E.G. during the first quarter of 2016. OSM decreased $34 million primarily due to a more favorable exchange rate on expenses denominated in the Canadian Dollar and continued cost management, especially staffing and contract labor.
23
The
first quarter
of
2016
production expense rate (expense per boe) for North America E&P declined as cost reductions occurred at a rate faster than our production decline. The expense rate for International E&P declined due to reduced maintenance and project costs and lower operational costs in Libya. The OSM expense rate decreased due to the positive currency effects and the increased cost focus, as discussed above.
The following table provides production expense rates for each segment:
|
Three Months Ended March 31,
|
|||||||
|
($ per boe)
|
2016
|
2015
|
|||||
|
Production Expense Rate
|
|||||||
|
North America E&P
|
|
$6.17
|
|
|
$7.94
|
|
|
|
International E&P
|
|
$6.08
|
|
|
$6.40
|
|
|
|
Oil Sands Mining
(a)
|
|
$28.80
|
|
|
$34.78
|
|
|
|
(a)
|
Production expense per synthetic crude oil barrel (before royalties) includes direct production costs (less pre-development), shipping and handling and taxes other than income.
|
Marketing costs
decreased
$147 million
in the
first quarter of 2016
from the comparable 2015 period, consistent with the marketing revenues changes discussed above.
Exploration expenses
decreased
$66 million
primarily due to higher dry well costs in the first quarter of 2015 which included the Sodalita West #1 well in E.G. and the Key Largo well in the Gulf of Mexico. The following table summarizes the components of exploration expenses:
|
|
Three Months Ended March 31,
|
||||||
|
(In millions)
|
2016
|
2015
|
|||||
|
Exploration Expenses
|
|||||||
|
Unproved property impairments
|
$
|
11
|
|
$
|
9
|
|
|
|
Dry well costs
|
—
|
|
58
|
|
|||
|
Geological and geophysical
|
—
|
|
3
|
|
|||
|
Other
|
13
|
|
20
|
|
|||
|
Total exploration expenses
|
$
|
24
|
|
$
|
90
|
|
|
Depreciation, depletion and amortization
decreased
$212 million
primarily as a result of production volume decreases, a higher proved reserve base in Eagle Ford and as a result of the Gulf of Mexico disposition in 2015 discussed above. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, proved reserve and production volumes have an impact on DD&A expense.
The DD&A rate (expense per boe), which is impacted by changes in reserves, capitalized costs, and sales volume mix by field, can also cause changes to our DD&A. The following table provides DD&A rates for each segment. The DD&A rate for North America E&P decreased primarily as a result of a higher proved reserve base in Eagle Ford.
|
Three Months Ended March 31,
|
|||||||
|
($ per boe)
|
2016
|
2015
|
|||||
|
DD&A Rate
|
|||||||
|
North America E&P
|
|
$22.39
|
|
|
$26.85
|
|
|
|
International E&P
|
|
$5.68
|
|
|
$6.10
|
|
|
|
Oil Sands Mining
|
|
$11.30
|
|
|
$12.44
|
|
|
24
Taxes other than income
decreased $
19 million
in the
first quarter of 2016
. The following table summarizes the components of taxes other than income:
|
|
Three Months Ended March 31,
|
||||||
|
(In millions)
|
2016
|
2015
|
|||||
|
Production and severance
|
$
|
19
|
|
$
|
34
|
|
|
|
Ad valorem
|
13
|
|
16
|
|
|||
|
Other
|
16
|
|
17
|
|
|||
|
Total
|
$
|
48
|
|
$
|
67
|
|
|
General and administrative expenses
decreased
$20 million
primarily due to cost savings realized from the workforce reductions in 2015, as well as lower severance related expenses in the current year. This was partially offset by pension settlement charges in the first three months of 2016 which totaled
$48 million
compared to
$17 million
in the prior year.
Net interest and other
increased
$38 million
primarily due to higher net foreign currency loss and increased interest expense associated with our June 2015 debt issuance.
Provision (benefit) for income taxes
reflects an effective tax rate of
40%
in the
first quarter
of
2016
, as compared to
34%
in the
first quarter
of
2015
. See Note
8
to the consolidated financial statements for discussion of the effective tax rate.
Segment Income
(Loss)
Segment income (loss) represents income (loss) from operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments, unrealized gains or losses on commodity derivative instruments, or other items that affect comparability also are not allocated to operating segments.
The following table reconciles segment income (loss) to net income (loss):
|
|
Three Months Ended March 31,
|
||||||
|
(In millions)
|
2016
|
2015
|
|||||
|
North America E&P
|
$
|
(195
|
)
|
$
|
(161
|
)
|
|
|
International E&P
|
4
|
|
23
|
|
|||
|
Oil Sands Mining
|
(48
|
)
|
(19
|
)
|
|||
|
Segment income (loss)
|
(239
|
)
|
(157
|
)
|
|||
|
Items not allocated to segments, net of income taxes
|
(168
|
)
|
(119
|
)
|
|||
|
Net income (loss)
|
$
|
(407
|
)
|
$
|
(276
|
)
|
|
North America E&P segment loss
increased
$34 million
after-tax primarily due to lower price realizations and sales volumes, which was partially offset by lower DD&A and production expenses.
International E&P segment income
decreased
$19 million
after-tax primarily due to lower price realizations and sales volumes as well as reduced income from equity investments. These declines were partially offset by lower exploration, production and DD&A expenses.
Oil Sands Mining segment loss
increased
$29 million
after-tax primarily due to lower price realizations, partially offset by lower production expenses.
Critical Accounting Estimates
There have been no material changes or developments in the evaluation of the accounting estimates and the underlying assumptions or methodologies pertaining to our Critical Accounting Estimates disclosed in our Form 10-K for the year ended
December 31, 2015
, except as discussed below.
Fair Value Estimates - Goodwill
Goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. A triggering event related to price declines in our common stock required us to reassess our goodwill for impairment as of March 31, 2016. Based on the results of this assessment, we concluded no impairment was required. While the fair value of our International E&P reporting unit exceeded book value, subsequent commodity price and/or common stock declines may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.
25
Estimated Quantities of Net Reserves
Our December 31, 2015 proved reserves were calculated using the unweighted average of closing benchmark prices nearest to the first day of each month within the 12-month period ("SEC pricing"). The table below provides the 2015 SEC pricing for certain benchmark prices as well as the unweighted average for the first four months of 2016:
|
Unweighted 12-month 2015 Average
|
Unweighted 4-month 2016 Average
|
|
|
WTI Crude oil
|
$50.28
|
$35.67
|
|
Henry Hub natural gas
|
2.59
|
2.00
|
|
Brent crude oil
|
54.25
|
35.95
|
|
Natural gas liquids
|
17.32
|
13.16
|
Any significant future price change could have a material effect on the quantity and present value of our proved reserves. To the extent that commodity prices remain at lower levels throughout 2016, a portion of our proved reserves could be deemed uneconomic and no longer classified as proved. This could impact both proved developed producing reserves as well as proved undeveloped reserves. If prices remain at the 4-month average depicted above throughout 2016, a material volume of our proved reserves could become uneconomic and would have to be reclassified to non-proved reserve or resource category. Assuming lower SEC pricing in 2016, our OSM proved reserves represent the largest risk to be reclassified to non-proved reserve or resource category. However, any impact of lower SEC pricing will likely be partially offset by continued cost reduction efforts. Also, any volumes reclassified to non-proved reserves could return to proved reserves as commodity prices improve. In the event the OSM proved reserves are reclassified to non-proved reserves or resource, their classification will have no impact on future plans for production.
Accounting Standards Not Yet Adopted
See Note 2 to the consolidated financial statements.
Cash Flows
The following table presents sources and uses of cash and cash equivalents:
|
Three Months Ended March 31,
|
||||||
|
(In millions)
|
2016
|
2015
|
||||
|
Sources of cash and cash equivalents
|
|
|
|
|
||
|
Operating activities
|
$
|
74
|
|
$
|
309
|
|
|
Common stock issuance
|
1,232
|
|
—
|
|
||
|
Disposals of assets
|
17
|
|
2
|
|
||
|
Other
|
16
|
|
14
|
|
||
|
Total sources of cash and cash equivalents
|
$
|
1,339
|
|
$
|
325
|
|
|
Uses of cash and cash equivalents
|
||||||
|
Cash additions to property, plant and equipment
|
$
|
(454
|
)
|
$
|
(1,452
|
)
|
|
Dividends paid
|
(34
|
)
|
(142
|
)
|
||
|
Other
|
—
|
|
(3
|
)
|
||
|
Total uses of cash and cash equivalents
|
$
|
(488
|
)
|
$
|
(1,597
|
)
|
Cash flows generated from operating activities in the first quarter of 2016 were lower as the downturn in the commodity cycle continued. This continued downward pressure on price realizations, coupled with the lower net sales volumes, continues to negatively impact our cash flows from operating activities. In the first quarter of 2016, consolidated average liquids price realizations were down by approximately 35% and consolidated net sales volumes declined by 14% as compared to the prior year quarter.
Common stock issuance reflects net proceeds received in March 2016 from our public sale of common stock. See Liquidity and Capital Resources below for additional information.
26
Additions to property, plant and equipment are our most significant use of cash and cash equivalents. Total capital expenditures, including accruals, were 67% lower in the first quarter of 2016 consistent with a reduced Capital Program as compared to the prior year. The following table shows capital expenditures by segment and reconciles to additions to property, plant and equipment as presented in the consolidated statements of cash flows:
|
Three Months Ended March 31,
|
|||||||
|
(In millions)
|
2016
|
2015
|
|||||
|
North America E&P
|
$
|
315
|
|
$
|
933
|
|
|
|
International E&P
|
32
|
|
146
|
|
|||
|
Oil Sands Mining
|
9
|
|
21
|
|
|||
|
Corporate
|
3
|
|
2
|
|
|||
|
Total capital expenditures
|
359
|
|
1,102
|
|
|||
|
Decrease in capital expenditure accrual
|
95
|
|
350
|
|
|||
|
Total use of cash and cash equivalents for property, plant and equipment
|
$
|
454
|
|
$
|
1,452
|
|
|
In October 2015, we announced an adjustment to our quarterly dividend. See Capital Requirements below for additional information.
Liquidity and Capital Resources
In March 2016, we issued 166,750,000 shares of our common stock, par value $1 per share, at a price of $7.65 per share, excluding underwriting discounts and commissions, for net proceeds of $1,232 million. The proceeds will be used to strengthen our balance sheet and for general corporate purposes, including funding a portion of our Capital Program.
Also in March 2016, we increased our $3.0 billion unsecured Credit Facility by $300 million to a total of $3.3 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the increase.
Our main sources of liquidity are cash and cash equivalents, sales of non-core assets, internally generated cash flow from operations, capital market transactions, and our $3.3 billion Credit Facility. Our working capital requirements are supported by these sources and we may draw on our $3.3 billion Credit Facility to meet short-term cash requirements, or issue debt or equity securities through the shelf registration statement discussed below as part of our longer-term liquidity and capital management. Because of the alternatives available to us as discussed above, we believe that our short-term and long-term liquidity is adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, and other amounts that may ultimately be paid in connection with contingencies.
Due to decreases in crude oil and U.S. natural gas prices earlier this year, credit rating agencies recently reviewed many companies in the industry, including us. During the first quarter of 2016, our corporate credit rating was downgraded by: Standard & Poor's Ratings Services to BBB- (stable) from BBB (stable); by Fitch Ratings to BBB (negative) from BBB+ (stable); and by Moody's Investor Services, Inc. to Ba1 (negative) from Baa1 (stable). Any further rating downgrades could increase our future cost of financing or limit our ability to access capital. See Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2015 for a discussion of how a further downgrade in our credit ratings could affect us.
Capital Resources
Credit Arrangements and Borrowings
At
March 31, 2016
, we had no borrowings against our revolving credit facility.
At
March 31, 2016
, we had
$7.3 billion
in long-term debt outstanding, with our next debt maturity in the amount of $680 million due in the fourth quarter of 2017.
We do not have any triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit ratings.
Shelf Registration
We have a universal shelf registration statement filed with the SEC under which we, as a "well-known seasoned issuer" for purposes of SEC rules, have the ability to issue and sell an indeterminate amount of various types of equity and debt securities.
27
Asset Disposals
Since August 2015, we have announced or closed non-core asset sales of approximately $1.3 billion, surpassing our targeted range of $750 million to $1 billion. In the largest transaction, we will divest all of our Wyoming upstream and midstream assets for $870 million, before closing adjustments, with closing expected mid-year 2016. In separate transactions, we signed agreements for the sale of our 10% working interest in the outside-operated Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Colorado, and certain undeveloped acreage in West Texas for a combined total of approximately $80 million, before closing adjustments, with closing expected mid-year 2016.
Cash-Adjusted Debt-To-Capital Ratio
Our cash-adjusted debt-to-capital ratio (total debt-minus-cash and cash equivalents to total debt-plus-equity-minus-cash and cash equivalents) was
21%
at
March 31, 2016
, compared to
25%
at
December 31, 2015
.
|
|
March 31,
|
December 31,
|
|||||
|
(In millions)
|
2016
|
2015
|
|||||
|
Long-term debt due within one year
|
$
|
1
|
|
$
|
1
|
|
|
|
Long-term debt
|
7,280
|
|
7,276
|
|
|||
|
Total debt
|
$
|
7,281
|
|
$
|
7,277
|
|
|
|
Cash and cash equivalents
|
$
|
2,072
|
|
$
|
1,221
|
|
|
|
Equity
|
$
|
19,351
|
|
$
|
18,553
|
|
|
|
Calculation:
|
|
|
|
|
|||
|
Total debt
|
$
|
7,281
|
|
$
|
7,277
|
|
|
|
Minus cash and cash equivalents
|
2,072
|
|
1,221
|
|
|||
|
Total debt minus cash, cash equivalents
|
$
|
5,209
|
|
$
|
6,056
|
|
|
|
Total debt
|
$
|
7,281
|
|
$
|
7,277
|
|
|
|
Plus equity
|
19,351
|
|
18,553
|
|
|||
|
Minus cash and cash equivalents
|
2,072
|
|
1,221
|
|
|||
|
Total debt plus equity minus cash, cash equivalents
|
$
|
24,560
|
|
$
|
24,609
|
|
|
|
Cash-adjusted debt-to-capital ratio
|
21
|
%
|
25
|
%
|
|||
Capital Requirements
Our Board of Directors approved a Capital Program of $1.4 billion for 2016.
On April 27, 2016, our Board of Directors approved a dividend of $0.05 per share for the
first quarter of 2016
payable June 10, 2016 to stockholders of record at the close of business on May 18, 2016.
As of
March 31, 2016
, we plan to make contributions of up to
$48 million
to our funded pension plans during the remainder of 2016.
Contractual Cash Obligations
As of
March 31, 2016
, there are no material changes to our consolidated cash obligations to make future payments under existing contracts, as disclosed in our 2015 Annual Report on Form 10-K.
Environmental Matters
We have incurred and will continue to incur capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes.
There have been no significant changes to our environmental matters subsequent to
December 31, 2015
.
Other Contingencies
We are a defendant in a number of legal and administrative proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims, tax disputes and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.
28
Forward-Looking Statements
This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the "Exchange Act"). All statements other than statements of historical fact included or incorporated by reference in this report are forward-looking statements, including without limitation statements regarding: our operational and financial strategies, including project plans, drilling plans, maintenance activities, financial flexibility, strengthening of the balance sheet, productivity improvements, and drilling and completion efficiencies; our ability to effect those strategies and the expected timing and results thereof; our ability to complete the non-core asset sales, and the expected timing and results thereof; our financial and operational outlook and ability to fulfill that outlook; expectations regarding future economic and market conditions and their effects on our business; our 2016 Capital Program; our financial position, liquidity and capital resources; and the plans and objectives of our management for our future operations. In addition, many forward-looking statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “estimate,” “expect,” “target,” “plan,” “project,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. While we believe that our assumptions concerning future events are reasonable, a number of factors could cause results to differ materially from those indicated by such forward-looking statements including, but not limited to:
|
•
|
conditions in the oil and gas industry, including supply/demand levels and the resulting impact on price;
|
|
•
|
changes in expected reserve or production levels;
|
|
•
|
changes in political or economic conditions in the jurisdictions in which we operate;
|
|
•
|
capital available for exploration and development;
|
|
•
|
well production timing;
|
|
•
|
availability of drilling rigs, materials and labor;
|
|
•
|
difficulty in obtaining necessary approvals and permits;
|
|
•
|
non-performance by third parties of contractual obligations;
|
|
•
|
unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto;
|
|
•
|
cyber-attacks;
|
|
•
|
changes in safety, health, environmental and other regulations;
|
|
•
|
other geological, operating and economic considerations; and
|
|
•
|
the risk factors, forward-looking statements and challenges and uncertainties described in our 2015 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other filings with the SEC.
|
All forward-looking statements included in this report are based on information available to us on the date of this report. Except as required by law, we assume no duty or obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.
29
Item 3. Quantitative and Qualitative Disclosures About Market Risk
For a detailed discussion of our risk management strategies and our derivative instruments, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk in our 2015 Annual Report on Form 10-K. Additional disclosures regarding our open derivative positions, including underlying notional quantities, how they are reported in our consolidated financial statements and how their fair values are measured, may be found in Notes
11
and
12
to the consolidated financial statements.
Commodity Price Risk
During the first three months of 2016, we entered into crude oil and natural gas derivatives, indexed to NYMEX WTI and Henry Hub, related to a portion of our forecasted North America E&P sales. The following tables provide a summary of open positions as of
March 31, 2016
and the weighted average price for those contracts:
|
Crude Oil
(a)
|
||||
|
2016
|
Year Ending December 31,
|
|||
|
Second Quarter
|
Third Quarter
|
Fourth Quarter
|
2017
|
|
|
Three-Way Collars
(b)
|
||||
|
Volume (Bbls/day)
|
39,000
|
37,000
|
37,000
|
—
|
|
Price per Bbl
|
||||
|
Ceiling
|
$55.47
|
$54.52
|
$54.52
|
—
|
|
Floor
|
$51.56
|
$50.83
|
$50.83
|
—
|
|
Sold put
|
$41.67
|
$41.22
|
$41.22
|
—
|
|
Options
(c)
|
||||
|
Volume (Bbls/day)
|
10,000
|
10,000
|
10,000
|
25,000
|
|
Price per Bbl
|
$72.39
|
$72.39
|
$72.39
|
$60.67
|
|
Swaps
|
||||
|
Volume (Bbls/day)
|
25,000
|
—
|
—
|
—
|
|
Price per Bbl
|
$39.25
|
—
|
—
|
—
|
(a)
Subsequent to March 31, 2016, we entered into 10,000 Bbls/day of two-way collars for July - December 2016 with a ceiling price of $50.00 and a floor price of $41.55. We also entered into 10,000 Bbls/day of 2016 three-way collars for May - December 2016 with a ceiling price of $58.51, a floor price of $48.00, and a sold put price of $40.00, traded in conjunction with sold call options of 10,000 Bbls/day for 2017 at $65.00.
|
(b)
|
A counterparty has the option, exercisable on June 30, 2016, to extend three-way collars for
2,000
Bbls/day through the remainder of 2016 at a ceiling of
$73.13
, floor of
$65.00
and sold put of
$50.00
.
|
|
(c)
|
Call options settle monthly.
|
|
Natural Gas
(a)
|
||||
|
2016
|
Year Ending December 31,
|
|||
|
Second Quarter
|
Third Quarter
|
Fourth Quarter
|
2017
|
|
|
Three-Way Collars
(b)
|
||||
|
Volume (MMBtu/day)
|
20,000
|
20,000
|
20,000
|
20,000
|
|
Price per MMBtu
|
||||
|
Ceiling
|
$2.93
|
$2.93
|
$2.93
|
$3.07
|
|
Floor
|
$2.50
|
$2.50
|
$2.50
|
$2.75
|
|
Sold put
|
$2.00
|
$2.00
|
$2.00
|
$2.25
|
|
(a)
|
Subsequent to March 31, 2016, we entered into 20,000 MMBtu/day of 2017 three-way collars with a ceiling price of $3.50, a floor price of $2.75, and a sold put price of $2.25.
|
|
(b)
|
Counterparty has the option to execute fixed-price swaps (swaptions) at a weighted average price of
$2.93
per MMBtu indexed to NYMEX Henry Hub, which is exercisable on December 22, 2016. If counterparty exercises, the term of the fixed-price swaps would be for the calendar year 2017 and, if all such options are exercised,
20,000
MMBtu per day.
|
The following table provides a sensitivity analysis of the projected incremental effect on income (loss) from operations of a hypothetical 10% change in NYMEX WTI and Henry Hub prices on our open commodity derivative instruments as of
March 31, 2016
.
30
|
(In millions)
|
Hypothetical Price Increase of 10%
|
Hypothetical Price Decrease of 10%
|
||||
|
Crude oil derivatives
|
$
|
(46
|
)
|
$
|
38
|
|
|
Natural gas derivatives
|
(3
|
)
|
3
|
|
||
|
Total
|
$
|
(49
|
)
|
$
|
41
|
|
Interest Rate Risk
Sensitivity analysis of the incremental effect of a hypothetical 10% change in interest rates on financial assets and liabilities as of
March 31, 2016
, is provided in the following table.
|
(In millions)
|
Fair Value
|
Incremental Change in Fair Value
|
|||||
|
Financial assets (liabilities):
(a)
|
|||||||
|
Interest rate swap agreements
|
$
|
12
|
|
(b)
|
$
|
1
|
|
|
Long term debt, including amounts due within one year
|
$
|
(6,575
|
)
|
(b)(c)
|
$
|
(310
|
)
|
|
(a)
|
Fair value of cash and cash equivalents, receivables, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.
|
|
(b)
|
Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.
|
|
(c)
|
Excludes capital leases.
|
Item 4. Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this Report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as of
March 31, 2016
.
During the
first quarter of 2016
, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
31
Part II – OTHER INFORMATION
Item 1. Legal and Administrative Proceedings
We are a defendant in a number of legal and administrative proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims, tax disputes and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.
Item 1A. Risk Factors
We are subject to various risks and uncertainties in the course of our business. There have been no material changes to the risk factors under Item 1A. Risk Factors in our
2015
Annual Report on Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table provides information about purchases by Marathon Oil during the quarter ended
March 31, 2016
, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Exchange Act of 1934.
|
Total Number of
|
Average Price
|
Total Number of
Shares Purchased
as Part of
Publicly Announced
|
Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
|
||||||
|
Period
|
Shares Purchased
(a)
|
Paid per Share
|
Plans or Programs
|
Plans or Programs
|
|||||
|
01/01/16 - 01/31/16
|
4,032
|
|
$12.96
|
—
|
|
n/a
|
|||
|
02/01/16 - 02/29/16
|
7,402
|
|
$8.01
|
—
|
|
n/a
|
|||
|
03/01/16 - 03/31/16
|
290
|
|
$7.82
|
—
|
|
n/a
|
|||
|
Total
|
11,724
|
|
$9.71
|
—
|
|
||||
|
(a)
|
11,724
shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.
|
Item 6. Exhibits
The information required by this Item 6 is set forth in the Exhibit Index accompanying this Form 10-Q.
32
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
May 5, 2016
|
MARATHON OIL CORPORATION
|
|
|
|
|
|
|
|
By:
|
/s/ Gary E. Wilson
|
|
|
Gary E. Wilson
|
|
|
|
Vice President, Controller and Chief Accounting Officer
|
|
|
(Duly Authorized Officer)
|
||
33
Exhibit Index
|
|
|
Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
|
||||||
|
Exhibit Number
|
Exhibit Description
|
Form
|
Exhibit
|
Filing Date
|
||||
|
3.1
|
Restated Certificate of Incorporation of Marathon Oil Corporation
|
10-Q
|
3.1
|
8/8/2013
|
||||
|
3.2
|
Marathon Oil Corporation By-laws (Amended and restated as of February 24, 2016)
|
8-K
|
3.1
|
3/1/2016
|
||||
|
3.3
|
Specimen of Common Stock Certificate
|
10-K
|
3.3
|
2/28/2014
|
||||
|
4.1
|
Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the SEC upon its request
|
10-K
|
4.1
|
2/28/2014
|
||||
|
12.1
|
Computation of Ratio of Earnings to Fixed Charges*
|
|||||||
|
31.1
|
Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934*
|
|||||||
|
31.2
|
Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934*
|
|||||||
|
32.1
|
Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350*
|
|||||||
|
32.2
|
Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350*
|
|||||||
|
101.INS
|
XBRL Instance Document*
|
|||||||
|
101.SCH
|
XBRL Taxonomy Extension Schema*
|
|||||||
|
101.CAL
|
XBRL Taxonomy Extension Calculation Linkbase*
|
|||||||
|
101.DEF
|
XBRL Taxonomy Extension Definition Linkbase*
|
|||||||
|
101.LAB
|
XBRL Taxonomy Extension Label Linkbase*
|
|||||||
|
101.PRE
|
XBRL Taxonomy Extension Presentation Linkbase*
|
|||||||
|
*
|
Filed herewith.
|
|||||||
TABLE OF CONTENTS
Part I - Financial InformationprintItem 1. Financial StatementsprintItem 2. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsprintItem 3. Quantitative and Qualitative Disclosures About Market RiskprintItem 4. Controls and ProceduresprintPart II Other InformationprintItem 1. Legal and Administrative ProceedingsprintItem 1A. Risk FactorsprintItem 2. Unregistered Sales Of Equity Securities and Use Of ProceedsprintItem 6. Exhibitsprint