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Share Name | Share Symbol | Market | Type |
---|---|---|---|
Marathon Oil Corp | NYSE:MRO | NYSE | Common Stock |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
0.31 | 1.19% | 26.40 | 26.53 | 26.01 | 26.25 | 9,055,755 | 01:00:00 |
(Mark One)
|
|
[X]
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
|
|
For the Quarterly Period Ended September 30, 2016
|
[ ]
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
|
|
For the transition period from _____ to _____
|
Delaware
|
|
25-0996816
|
(State or other jurisdiction of incorporation or organization)
|
|
(I.R.S. Employer Identification No.)
|
Large accelerated filer
þ
|
Accelerated filer
o
|
Non-accelerated filer
o
(Do not check if a smaller reporting company)
|
Smaller reporting company
o
|
|
Table of Contents
|
|
|
|
Page
|
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||||
|
September 30,
|
|
September 30,
|
||||||||||||
(In millions, except per share data)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Revenues and other income:
|
|
|
|
|
|
|
|
||||||||
Sales and other operating revenues, including related party
|
$
|
1,020
|
|
|
$
|
1,300
|
|
|
$
|
2,604
|
|
|
$
|
3,887
|
|
Marketing revenues
|
80
|
|
|
84
|
|
|
227
|
|
|
471
|
|
||||
Income from equity method investments
|
59
|
|
|
36
|
|
|
110
|
|
|
98
|
|
||||
Net gain (loss) on disposal of assets
|
47
|
|
|
(109
|
)
|
|
281
|
|
|
(108
|
)
|
||||
Other income
|
23
|
|
|
12
|
|
|
39
|
|
|
38
|
|
||||
Total revenues and other income
|
1,229
|
|
|
1,323
|
|
|
3,261
|
|
|
4,386
|
|
||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|||||
Production
|
295
|
|
|
406
|
|
|
973
|
|
|
1,300
|
|
||||
Marketing, including purchases from related parties
|
80
|
|
|
84
|
|
|
226
|
|
|
471
|
|
||||
Other operating
|
189
|
|
|
93
|
|
|
393
|
|
|
281
|
|
||||
Exploration
|
83
|
|
|
585
|
|
|
296
|
|
|
786
|
|
||||
Depreciation, depletion and amortization
|
594
|
|
|
717
|
|
|
1,764
|
|
|
2,289
|
|
||||
Impairments
|
47
|
|
|
337
|
|
|
48
|
|
|
381
|
|
||||
Taxes other than income
|
39
|
|
|
46
|
|
|
126
|
|
|
191
|
|
||||
General and administrative
|
105
|
|
|
125
|
|
|
388
|
|
|
464
|
|
||||
Total costs and expenses
|
1,432
|
|
|
2,393
|
|
|
4,214
|
|
|
6,163
|
|
||||
Income (loss) from operations
|
(203
|
)
|
|
(1,070
|
)
|
|
(953
|
)
|
|
(1,777
|
)
|
||||
Net interest and other
|
(87
|
)
|
|
(75
|
)
|
|
(258
|
)
|
|
(180
|
)
|
||||
Income (loss) before income taxes
|
(290
|
)
|
|
(1,145
|
)
|
|
(1,211
|
)
|
|
(1,957
|
)
|
||||
Provision (benefit) for income taxes
|
(98
|
)
|
|
(396
|
)
|
|
(442
|
)
|
|
(546
|
)
|
||||
Net income (loss)
|
$
|
(192
|
)
|
|
$
|
(749
|
)
|
|
$
|
(769
|
)
|
|
$
|
(1,411
|
)
|
Net income (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Basic
|
$
|
(0.23
|
)
|
|
$
|
(1.11
|
)
|
|
$
|
(0.95
|
)
|
|
$
|
(2.09
|
)
|
Diluted
|
$
|
(0.23
|
)
|
|
$
|
(1.11
|
)
|
|
$
|
(0.95
|
)
|
|
$
|
(2.09
|
)
|
Dividends per share
|
$
|
0.05
|
|
|
$
|
0.21
|
|
|
$
|
0.15
|
|
|
$
|
0.63
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Basic
|
847
|
|
|
677
|
|
|
809
|
|
|
677
|
|
||||
Diluted
|
847
|
|
|
677
|
|
|
809
|
|
|
677
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
||||||||||||
|
September 30,
|
|
September 30,
|
||||||||||||
(In millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Net income (loss)
|
$
|
(192
|
)
|
|
$
|
(749
|
)
|
|
$
|
(769
|
)
|
|
$
|
(1,411
|
)
|
Other comprehensive income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
||||
Postretirement and postemployment plans
|
|
|
|
|
|
|
|
|
|
|
|
||||
Change in actuarial loss and other
|
—
|
|
|
(2
|
)
|
|
(5
|
)
|
|
160
|
|
||||
Income tax provision (benefit)
|
—
|
|
|
(1
|
)
|
|
2
|
|
|
(58
|
)
|
||||
Postretirement and postemployment plans, net of tax
|
—
|
|
|
(3
|
)
|
|
(3
|
)
|
|
102
|
|
||||
Other, net of tax
|
3
|
|
|
—
|
|
|
1
|
|
|
—
|
|
||||
Other comprehensive income (loss)
|
3
|
|
|
(3
|
)
|
|
(2
|
)
|
|
102
|
|
||||
Comprehensive income (loss)
|
$
|
(189
|
)
|
|
$
|
(752
|
)
|
|
$
|
(771
|
)
|
|
$
|
(1,309
|
)
|
|
September 30,
|
|
December 31,
|
||||
(In millions, except per share data)
|
2016
|
|
2015
|
||||
Assets
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
1,953
|
|
|
$
|
1,221
|
|
Receivables, less reserve of $4 and $4
|
783
|
|
|
912
|
|
||
Inventories
|
221
|
|
|
313
|
|
||
Other current assets
|
85
|
|
|
144
|
|
||
Total current assets
|
3,042
|
|
|
2,590
|
|
||
Equity method investments
|
931
|
|
|
1,003
|
|
||
Property, plant and equipment, less accumulated depreciation,
|
|
|
|
|
|
||
depletion and amortization of $21,775 and $23,260
|
25,976
|
|
|
27,061
|
|
||
Goodwill
|
115
|
|
|
115
|
|
||
Other noncurrent assets
|
2,246
|
|
|
1,542
|
|
||
Total assets
|
$
|
32,310
|
|
|
$
|
32,311
|
|
Liabilities
|
|
|
|
|
|
||
Current liabilities:
|
|
|
|
|
|
||
Accounts payable
|
$
|
964
|
|
|
$
|
1,313
|
|
Payroll and benefits payable
|
121
|
|
|
133
|
|
||
Accrued taxes
|
66
|
|
|
132
|
|
||
Other current liabilities
|
256
|
|
|
150
|
|
||
Long-term debt due within one year
|
1
|
|
|
1
|
|
||
Total current liabilities
|
1,408
|
|
|
1,729
|
|
||
Long-term debt
|
7,277
|
|
|
7,276
|
|
||
Deferred tax liabilities
|
2,399
|
|
|
2,441
|
|
||
Defined benefit postretirement plan obligations
|
400
|
|
|
403
|
|
||
Asset retirement obligations
|
1,607
|
|
|
1,601
|
|
||
Deferred credits and other liabilities
|
297
|
|
|
308
|
|
||
Total liabilities
|
13,388
|
|
|
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 – 90 million and 93 million shares
|
(3,406
|
)
|
|
(3,554
|
)
|
||
Additional paid-in capital
|
7,442
|
|
|
6,498
|
|
||
Retained earnings
|
14,086
|
|
|
14,974
|
|
||
Accumulated other comprehensive loss
|
(137
|
)
|
|
(135
|
)
|
||
Total stockholders' equity
|
18,922
|
|
|
18,553
|
|
||
Total liabilities and stockholders' equity
|
$
|
32,310
|
|
|
$
|
32,311
|
|
|
Nine Months Ended
|
||||||
|
September 30,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
Increase (decrease) in cash and cash equivalents
|
|
|
|
||||
Operating activities:
|
|
|
|
|
|
||
Net income (loss)
|
$
|
(769
|
)
|
|
$
|
(1,411
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
||
Depreciation, depletion and amortization
|
1,764
|
|
|
2,289
|
|
||
Impairments
|
48
|
|
|
381
|
|
||
Exploratory dry well costs and unproved property impairments
|
203
|
|
|
708
|
|
||
Net (gain) loss on disposal of assets
|
(281
|
)
|
|
108
|
|
||
Deferred income taxes
|
(504
|
)
|
|
(590
|
)
|
||
Net (gain) loss on derivative instruments
|
48
|
|
|
(88
|
)
|
||
Net cash received (paid) in settlement of derivative instruments
|
51
|
|
|
18
|
|
||
Pension and other postretirement benefits, net
|
2
|
|
|
9
|
|
||
Stock based compensation
|
37
|
|
|
34
|
|
||
Equity method investments, net
|
26
|
|
|
41
|
|
||
Changes in:
|
|
|
|
|
|||
Current receivables
|
140
|
|
|
738
|
|
||
Inventories
|
81
|
|
|
30
|
|
||
Current accounts payable and accrued liabilities
|
(236
|
)
|
|
(954
|
)
|
||
All other operating, net
|
8
|
|
|
(100
|
)
|
||
Net cash provided by operating activities
|
618
|
|
|
1,213
|
|
||
Investing activities:
|
|
|
|
|
|
||
Additions to property, plant and equipment
|
(983
|
)
|
|
(2,948
|
)
|
||
Acquisitions, net of cash acquired
|
(902
|
)
|
|
—
|
|
||
Disposal of assets
|
837
|
|
|
105
|
|
||
Equity method investments - return of capital
|
47
|
|
|
61
|
|
||
Purchases of short-term investments
|
—
|
|
|
(925
|
)
|
||
Maturities of short-term investments
|
—
|
|
|
225
|
|
||
All other investing, net
|
2
|
|
|
22
|
|
||
Net cash used in investing activities
|
(999
|
)
|
|
(3,460
|
)
|
||
Financing activities:
|
|
|
|
|
|
||
Borrowings
|
—
|
|
|
1,996
|
|
||
Debt issuance costs
|
—
|
|
|
(19
|
)
|
||
Debt repayments
|
(1
|
)
|
|
(34
|
)
|
||
Common stock issuance
|
1,236
|
|
|
—
|
|
||
Dividends paid
|
(119
|
)
|
|
(427
|
)
|
||
All other financing, net
|
—
|
|
|
14
|
|
||
Net cash provided by financing activities
|
1,116
|
|
|
1,530
|
|
||
Effect of exchange rate on cash and cash equivalents
|
(3
|
)
|
|
(1
|
)
|
||
Net increase (decrease) in cash and cash equivalents
|
732
|
|
|
(718
|
)
|
||
Cash and cash equivalents at beginning of period
|
1,221
|
|
|
2,398
|
|
||
Cash and cash equivalents at end of period
|
$
|
1,953
|
|
|
$
|
1,680
|
|
4
.
|
Income (Loss) per Common Share
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
||||||||||||
(In millions, except per share data)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Net income (loss)
|
$
|
(192
|
)
|
|
$
|
(749
|
)
|
|
$
|
(769
|
)
|
|
$
|
(1,411
|
)
|
|
|
|
|
|
|
|
|
||||||||
Weighted average common shares outstanding
|
847
|
|
|
677
|
|
|
809
|
|
|
677
|
|
||||
Weighted average common shares, diluted
|
847
|
|
|
677
|
|
|
809
|
|
|
677
|
|
||||
Net income (loss) per share:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
(0.23
|
)
|
|
$
|
(1.11
|
)
|
|
$
|
(0.95
|
)
|
|
$
|
(2.09
|
)
|
Diluted
|
$
|
(0.23
|
)
|
|
$
|
(1.11
|
)
|
|
$
|
(0.95
|
)
|
|
$
|
(2.09
|
)
|
6
.
|
Dispositions
|
•
|
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.
|
|
Three Months Ended September 30, 2016
|
||||||||||||||||||
|
|
|
Not Allocated
|
|
|
||||||||||||||
(In millions)
|
N.A. E&P
|
|
Int'l E&P
|
|
OSM
|
|
to Segments
|
|
Total
|
||||||||||
Sales and other operating revenues
|
$
|
604
|
|
|
$
|
152
|
|
|
$
|
239
|
|
|
$
|
25
|
|
(c)
|
$
|
1,020
|
|
Marketing revenues
|
44
|
|
|
36
|
|
|
—
|
|
|
—
|
|
|
80
|
|
|||||
Total revenues
|
648
|
|
|
188
|
|
|
239
|
|
|
25
|
|
|
1,100
|
|
|||||
Income from equity method investments
|
—
|
|
|
59
|
|
|
—
|
|
|
—
|
|
|
59
|
|
|||||
Net gain on disposal of assets and other income
|
19
|
|
|
7
|
|
|
—
|
|
|
44
|
|
(d)
|
70
|
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
||||||||||
Production expenses
|
113
|
|
|
47
|
|
|
135
|
|
|
—
|
|
|
295
|
|
|||||
Marketing costs
|
45
|
|
|
35
|
|
|
—
|
|
|
—
|
|
|
80
|
|
|||||
Exploration expenses
|
35
|
|
|
10
|
|
|
—
|
|
|
38
|
|
|
83
|
|
|||||
Depreciation, depletion and amortization
|
443
|
|
|
66
|
|
|
72
|
|
|
13
|
|
|
594
|
|
|||||
Impairments
|
—
|
|
|
—
|
|
|
—
|
|
|
47
|
|
(e)
|
47
|
|
|||||
Other expenses
(a)
|
85
|
|
|
18
|
|
|
9
|
|
|
182
|
|
(f)
|
294
|
|
|||||
Taxes other than income
|
35
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
39
|
|
|||||
Net interest and other
|
—
|
|
|
—
|
|
|
—
|
|
|
87
|
|
|
87
|
|
|||||
Income tax provision (benefit)
|
(30
|
)
|
|
19
|
|
|
4
|
|
|
(91
|
)
|
|
(98
|
)
|
|||||
Segment income (loss) / Net income (loss)
|
$
|
(59
|
)
|
|
$
|
59
|
|
|
$
|
15
|
|
|
$
|
(207
|
)
|
|
$
|
(192
|
)
|
Capital expenditures
(b)
|
$
|
216
|
|
|
$
|
18
|
|
|
$
|
12
|
|
|
$
|
3
|
|
|
$
|
249
|
|
(a)
|
Includes other operating expenses and general and administrative expenses.
|
(b)
|
Includes accruals.
|
(c)
|
Unrealized gain on commodity derivative instruments.
|
(d)
|
Primarily related to certain non-operated assets in West Texas and New Mexico. (see Note
6
).
|
(e)
|
Proved property impairments (see Note
14
).
|
(f)
|
Includes termination payment on our Gulf of Mexico deepwater drilling rig contract of $
113 million
and pension settlement loss of
$14 million
(see Note
8
).
|
|
Three Months Ended September 30, 2015
|
||||||||||||||||||
|
|
|
Not Allocated
|
|
|
||||||||||||||
(In millions)
|
N.A. E&P
|
|
Int'l E&P
|
|
OSM
|
|
to Segments
|
|
Total
|
||||||||||
Sales and other operating revenues
|
$
|
796
|
|
|
$
|
182
|
|
|
$
|
242
|
|
|
$
|
80
|
|
(c)
|
$
|
1,300
|
|
Marketing revenues
|
57
|
|
|
25
|
|
|
2
|
|
|
—
|
|
|
84
|
|
|||||
Total revenues
|
853
|
|
|
207
|
|
|
244
|
|
|
80
|
|
|
1,384
|
|
|||||
Income (loss) from equity method investments
|
—
|
|
|
48
|
|
|
—
|
|
|
(12
|
)
|
(d)
|
36
|
|
|||||
Net gain (loss) on disposal of assets and other income
|
6
|
|
|
6
|
|
|
—
|
|
|
(109
|
)
|
(e)
|
(97
|
)
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
||||||||||
Production expenses
|
179
|
|
|
61
|
|
|
166
|
|
|
—
|
|
|
406
|
|
|||||
Marketing costs
|
56
|
|
|
25
|
|
|
3
|
|
|
—
|
|
|
84
|
|
|||||
Exploration expenses
|
22
|
|
|
10
|
|
|
—
|
|
|
553
|
|
(f)
|
585
|
|
|||||
Depreciation, depletion and amortization
|
549
|
|
|
79
|
|
|
76
|
|
|
13
|
|
|
717
|
|
|||||
Impairments
|
—
|
|
|
—
|
|
|
4
|
|
|
333
|
|
(g)
|
337
|
|
|||||
Other expenses
(a)
|
106
|
|
|
25
|
|
|
8
|
|
|
79
|
|
(h)
|
218
|
|
|||||
Taxes other than income
|
42
|
|
|
—
|
|
|
5
|
|
|
(1
|
)
|
|
46
|
|
|||||
Net interest and other
|
—
|
|
|
—
|
|
|
—
|
|
|
75
|
|
|
75
|
|
|||||
Income tax provision (benefit)
|
(34
|
)
|
|
32
|
|
|
(7
|
)
|
|
(387
|
)
|
|
(396
|
)
|
|||||
Segment income (loss) / Net income (loss)
|
$
|
(61
|
)
|
|
$
|
29
|
|
|
$
|
(11
|
)
|
|
$
|
(706
|
)
|
|
$
|
(749
|
)
|
Capital expenditures
(b)
|
$
|
564
|
|
|
$
|
30
|
|
|
$
|
(11
|
)
|
|
$
|
12
|
|
|
$
|
595
|
|
(a)
|
Includes other operating expenses and general and administrative expenses.
|
(b)
|
Includes accruals.
|
(c)
|
Unrealized gain on commodity derivative instruments.
|
(d)
|
Partial impairment of investment in equity method investee (see Note
14
).
|
(e)
|
Includes loss on sale of East Africa exploration acreage (see Note
6
.).
|
(f)
|
Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (see Note
13
).
|
(g)
|
Proved property impairments (see Note
14
).
|
(h)
|
Includes pension settlement loss of
$18 million
(see Note
8
) and severance related expenses associated with workforce reductions of
$4 million
.
|
|
Nine Months Ended September 30, 2016
|
||||||||||||||||||
|
|
|
Not Allocated
|
|
|
||||||||||||||
(In millions)
|
N.A. E&P
|
|
Int'l E&P
|
|
OSM
|
|
to Segments
|
|
Total
|
||||||||||
Sales and other operating revenues
|
$
|
1,714
|
|
|
$
|
407
|
|
|
$
|
572
|
|
|
$
|
(89
|
)
|
(c)
|
$
|
2,604
|
|
Marketing revenues
|
128
|
|
|
74
|
|
|
25
|
|
|
—
|
|
|
227
|
|
|||||
Total revenues
|
1,842
|
|
|
481
|
|
|
597
|
|
|
(89
|
)
|
|
2,831
|
|
|||||
Income from equity method investments
|
—
|
|
|
110
|
|
|
—
|
|
|
—
|
|
|
110
|
|
|||||
Net gain on disposal of assets and other income
|
22
|
|
|
20
|
|
|
1
|
|
|
277
|
|
(d)
|
320
|
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
||||||||||
Production expenses
|
376
|
|
|
156
|
|
|
441
|
|
|
—
|
|
|
973
|
|
|||||
Marketing costs
|
129
|
|
|
72
|
|
|
25
|
|
|
—
|
|
|
226
|
|
|||||
Exploration expenses
|
90
|
|
|
20
|
|
|
7
|
|
|
179
|
|
(e)
|
296
|
|
|||||
Depreciation, depletion and amortization
|
1,363
|
|
|
184
|
|
|
181
|
|
|
36
|
|
|
1,764
|
|
|||||
Impairments
|
1
|
|
|
—
|
|
|
—
|
|
|
47
|
|
(f)
|
48
|
|
|||||
Other expenses
(a)
|
300
|
|
|
56
|
|
|
25
|
|
|
400
|
|
(g)
|
781
|
|
|||||
Taxes other than income
|
112
|
|
|
—
|
|
|
13
|
|
|
1
|
|
|
126
|
|
|||||
Net interest and other
|
—
|
|
|
—
|
|
|
—
|
|
|
258
|
|
|
258
|
|
|||||
Income tax provision (benefit)
|
(183
|
)
|
|
5
|
|
|
(23
|
)
|
|
(241
|
)
|
|
(442
|
)
|
|||||
Segment income (loss) / Net income (loss)
|
$
|
(324
|
)
|
|
$
|
118
|
|
|
$
|
(71
|
)
|
|
$
|
(492
|
)
|
|
$
|
(769
|
)
|
Capital expenditures
(b)
|
$
|
684
|
|
|
$
|
62
|
|
|
$
|
28
|
|
|
$
|
11
|
|
|
$
|
785
|
|
(a)
|
Includes other operating expenses and general and administrative expenses.
|
(c)
|
Unrealized loss on commodity derivative instruments.
|
(d)
|
Primarily related to net gain on disposal of assets (see Note
6
).
|
(e)
|
Primarily associated with impairments associated with decision to not drill remaining Gulf of Mexico undeveloped leases (see Note
13
).
|
(f)
|
Proved property impairments (see Note
14
).
|
(g)
|
Includes termination payment on our Gulf of Mexico deepwater drilling rig contract of $
113 million
and includes pension settlement loss of
$93 million
and severance related expenses associated with workforce reductions of
$8 million
(see Note
8
).
|
|
Nine Months Ended September 30, 2015
|
||||||||||||||||||
|
|
|
Not Allocated
|
|
|
||||||||||||||
(In millions)
|
N.A. E&P
|
|
Int'l E&P
|
|
OSM
|
|
to Segments
|
|
Total
|
||||||||||
Sales and other operating revenues
|
$
|
2,639
|
|
|
$
|
575
|
|
|
$
|
614
|
|
|
$
|
59
|
|
(c)
|
$
|
3,887
|
|
Marketing revenues
|
345
|
|
|
81
|
|
|
45
|
|
|
—
|
|
|
471
|
|
|||||
Total revenues
|
2,984
|
|
|
656
|
|
|
659
|
|
|
59
|
|
|
4,358
|
|
|||||
Income (loss) from equity method investments
|
—
|
|
|
110
|
|
|
—
|
|
|
(12
|
)
|
(d)
|
98
|
|
|||||
Net gain (loss) on disposal of assets and other income
|
17
|
|
|
20
|
|
|
1
|
|
|
(108
|
)
|
(e)
|
(70
|
)
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
||||||||||
Production expenses
|
560
|
|
|
192
|
|
|
548
|
|
|
—
|
|
|
1,300
|
|
|||||
Marketing costs
|
348
|
|
|
79
|
|
|
44
|
|
|
—
|
|
|
471
|
|
|||||
Exploration expenses
|
148
|
|
|
85
|
|
|
—
|
|
|
553
|
|
(f)
|
786
|
|
|||||
Depreciation, depletion and amortization
|
1,866
|
|
|
214
|
|
|
173
|
|
|
36
|
|
|
2,289
|
|
|||||
Impairments
|
—
|
|
|
—
|
|
|
4
|
|
|
377
|
|
(g)
|
381
|
|
|||||
Other expenses
(a)
|
322
|
|
|
67
|
|
|
26
|
|
|
330
|
|
(h)
|
745
|
|
|||||
Taxes other than income
|
170
|
|
|
—
|
|
|
15
|
|
|
6
|
|
|
191
|
|
|||||
Net interest and other
|
—
|
|
|
—
|
|
|
—
|
|
|
180
|
|
|
180
|
|
|||||
Income tax provision (benefit)
|
(146
|
)
|
|
56
|
|
|
(43
|
)
|
|
(413
|
)
|
(i)
|
(546
|
)
|
|||||
Segment income (loss) / Net income (loss)
|
$
|
(267
|
)
|
|
$
|
93
|
|
|
$
|
(107
|
)
|
|
$
|
(1,130
|
)
|
|
$
|
(1,411
|
)
|
Capital expenditures
(b)
|
$
|
2,048
|
|
|
$
|
275
|
|
|
$
|
26
|
|
|
$
|
26
|
|
|
$
|
2,375
|
|
(a)
|
Includes other operating expenses and general and administrative expenses.
|
(b)
|
Includes accruals.
|
(c)
|
Unrealized gain on commodity derivative instruments.
|
(d)
|
Partial impairment of investment in equity-method investee (see Note 14).
|
(e)
|
Includes loss on sale of East Africa exploration acreage (see Note
6
.).
|
(f)
|
Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (see Note
13
).
|
(g)
|
Proved property impairments (See Note
14
).
|
(h)
|
Includes pension settlement loss of $
99 million
(see Note 8) and severance related expenses associated with workforce reductions of
$47 million
.
|
(i)
|
Includes
$135 million
of deferred tax expense related to Alberta provincial corporate tax rate increase (see Note
9
).
|
|
Three Months Ended September 30,
|
||||||||||||||
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||
(In millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Service cost
|
$
|
6
|
|
|
$
|
11
|
|
|
$
|
1
|
|
|
$
|
—
|
|
Interest cost
|
9
|
|
|
12
|
|
|
3
|
|
|
3
|
|
||||
Expected return on plan assets
|
(12
|
)
|
|
(17
|
)
|
|
—
|
|
|
—
|
|
||||
Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
||||
– prior service cost (credit)
|
(2
|
)
|
|
(3
|
)
|
|
(1
|
)
|
|
(1
|
)
|
||||
– actuarial loss
|
4
|
|
|
5
|
|
|
—
|
|
|
1
|
|
||||
Net settlement loss
(a)
|
14
|
|
|
18
|
|
|
—
|
|
|
—
|
|
||||
Net curtailment loss
(b)
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
||||
Net periodic benefit cost
|
$
|
19
|
|
|
$
|
30
|
|
|
$
|
3
|
|
|
$
|
3
|
|
|
Nine Months Ended September 30,
|
||||||||||||||
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||
(In millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Service cost
|
$
|
18
|
|
|
$
|
35
|
|
|
$
|
3
|
|
|
$
|
2
|
|
Interest cost
|
30
|
|
|
39
|
|
|
8
|
|
|
8
|
|
||||
Expected return on plan assets
|
(40
|
)
|
|
(53
|
)
|
|
—
|
|
|
—
|
|
||||
Amortization:
|
|
|
|
|
|
|
|
|
|
|
|||||
– prior service cost (credit)
|
(7
|
)
|
|
(4
|
)
|
|
(3
|
)
|
|
(3
|
)
|
||||
– actuarial loss
|
11
|
|
|
19
|
|
|
—
|
|
|
1
|
|
||||
Net settlement loss
(a)
|
93
|
|
|
99
|
|
|
—
|
|
|
—
|
|
||||
Net curtailment loss (gain)
(b)
|
—
|
|
|
5
|
|
|
—
|
|
|
(4
|
)
|
||||
Net periodic benefit cost
|
$
|
105
|
|
|
$
|
140
|
|
|
$
|
8
|
|
|
$
|
4
|
|
(a)
|
Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan's total service and interest cost for that year.
|
(b)
|
Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans and the impact of discounting accruals for future benefits under the U.K. pension plan effective December 31, 2015.
|
|
|
2016
|
|
2015
|
||
Three months ended September 30
|
|
34
|
%
|
|
35
|
%
|
Nine months ended September 30
|
|
37
|
%
|
|
28
|
%
|
|
September 30,
|
|
December 31,
|
||||
(In millions)
|
2016
|
|
2015
|
||||
Liquid hydrocarbons, natural gas and bitumen
|
$
|
26
|
|
|
$
|
35
|
|
Supplies and other items
|
195
|
|
|
278
|
|
||
Inventories, at cost
|
$
|
221
|
|
|
$
|
313
|
|
|
September 30,
|
|
December 31,
|
||||
(In millions)
|
2016
|
|
2015
|
||||
North America E&P
|
$
|
14,391
|
|
|
$
|
15,226
|
|
International E&P
|
2,440
|
|
|
2,533
|
|
||
Oil Sands Mining
|
9,043
|
|
|
9,197
|
|
||
Corporate
|
102
|
|
|
105
|
|
||
Net property, plant and equipment
|
$
|
25,976
|
|
|
$
|
27,061
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
||||||||||||
(in millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Total impairments
|
$
|
47
|
|
|
$
|
337
|
|
|
$
|
48
|
|
|
$
|
381
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
||||||||||||
(In millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Exploration Expenses
|
|
|
|
|
|
|
|
||||||||
Unproved property impairments
|
$
|
28
|
|
|
$
|
563
|
|
|
$
|
172
|
|
|
$
|
612
|
|
Dry well costs
|
9
|
|
|
(3
|
)
|
|
31
|
|
|
96
|
|
||||
Geological and geophysical
|
1
|
|
|
8
|
|
|
1
|
|
|
23
|
|
||||
Other
|
45
|
|
|
17
|
|
|
92
|
|
|
55
|
|
||||
Total exploration expenses
|
$
|
83
|
|
|
$
|
585
|
|
|
$
|
296
|
|
|
$
|
786
|
|
|
September 30, 2016
|
||||||||||||||
(In millions)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Derivative instruments, assets
|
|
|
|
|
|
|
|
||||||||
Commodity (a)
|
$
|
—
|
|
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
4
|
|
Interest rate
|
—
|
|
|
10
|
|
|
—
|
|
|
10
|
|
||||
Derivative instruments, assets
|
$
|
—
|
|
|
$
|
14
|
|
|
$
|
—
|
|
|
$
|
14
|
|
Derivative instruments, liabilities
|
|
|
|
|
|
|
|
||||||||
Commodity (a)
|
$
|
—
|
|
|
$
|
43
|
|
|
$
|
—
|
|
|
$
|
43
|
|
Derivative instruments, liabilities
|
$
|
—
|
|
|
$
|
43
|
|
|
$
|
—
|
|
|
$
|
43
|
|
(a)
|
Derivative instruments are recorded on a net basis in our balance sheet (see Note
15
).
|
|
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 our balance sheet (see Note
15
).
|
|
Nine Months Ended September 30,
|
||||||||||||||
|
2016
|
|
2015
|
||||||||||||
(In millions)
|
Fair Value
|
|
Impairment
|
|
Fair Value
|
|
Impairment
|
||||||||
Long-lived assets held for use
|
$
|
15
|
|
|
$
|
48
|
|
|
$
|
58
|
|
|
$
|
381
|
|
|
September 30, 2016
|
|
December 31, 2015
|
||||||||||||
|
Fair
|
|
Carrying
|
|
Fair
|
|
Carrying
|
||||||||
(In millions)
|
Value
|
|
Amount
|
|
Value
|
|
Amount
|
||||||||
Financial assets
|
|
|
|
|
|
|
|
||||||||
Other noncurrent assets
|
$
|
112
|
|
|
$
|
118
|
|
|
$
|
104
|
|
|
$
|
118
|
|
Total financial assets
|
$
|
112
|
|
|
$
|
118
|
|
|
$
|
104
|
|
|
$
|
118
|
|
Financial liabilities
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other current liabilities
|
$
|
49
|
|
|
$
|
59
|
|
|
$
|
34
|
|
|
$
|
33
|
|
Long-term debt, including current portion (a)
|
7,345
|
|
|
7,292
|
|
|
6,723
|
|
|
7,291
|
|
||||
Deferred credits and other liabilities
|
123
|
|
|
117
|
|
|
97
|
|
|
95
|
|
||||
Total financial liabilities
|
$
|
7,517
|
|
|
$
|
7,468
|
|
|
$
|
6,854
|
|
|
$
|
7,419
|
|
|
September 30, 2016
|
|
|
||||||||||
(In millions)
|
Asset
|
|
Liability
|
|
Net Asset
|
|
Balance Sheet Location
|
||||||
Fair Value Hedges
|
|
|
|
|
|
|
|
||||||
Interest rate
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
8
|
|
|
Other noncurrent assets
|
Cash Flow Hedges
|
|
|
|
|
|
|
|
||||||
Interest rate
|
2
|
|
|
—
|
|
|
2
|
|
|
Other noncurrent assets
|
|||
Total Designated Hedges
|
$
|
10
|
|
|
$
|
—
|
|
|
$
|
10
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
September 30, 2016
|
|
|
||||||||||
(In millions)
|
Asset
|
|
Liability
|
|
Net Liability
|
|
Balance Sheet Location
|
||||||
Not Designated as Hedges
|
|
|
|
|
|
|
|
||||||
Commodity
|
$
|
4
|
|
|
$
|
30
|
|
|
$
|
26
|
|
|
Other current liabilities
|
Commodity
|
—
|
|
|
13
|
|
|
13
|
|
|
Deferred credits and other liabilities
|
|||
Total Not Designated as Hedges
|
$
|
4
|
|
|
$
|
43
|
|
|
$
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
|
||||||||||
(In millions)
|
Asset
|
|
Liability
|
|
Net Asset
|
|
Balance Sheet Location
|
||||||
Fair Value Hedges
|
|
|
|
|
|
|
|
||||||
Interest rate
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
8
|
|
|
Other noncurrent assets
|
|
|
|
|
|
|
|
|
||||||
Not Designated as Hedges
|
|
|
|
|
|
|
|
||||||
Commodity
|
$
|
51
|
|
|
$
|
1
|
|
|
$
|
50
|
|
|
Other current assets
|
|
September 30, 2016
|
|
December 31, 2015
|
||||||||
|
Aggregate Notional Amount
|
Weighted Average, LIBOR-Based,
|
|
Aggregate Notional Amount
|
Weighted Average, LIBOR-Based,
|
||||||
Maturity Dates
|
(in millions)
|
Floating Rate
|
|
(in millions)
|
Floating Rate
|
||||||
October 1, 2017
|
$
|
600
|
|
5.01
|
%
|
|
$
|
600
|
|
4.73
|
%
|
March 15, 2018
|
$
|
300
|
|
4.86
|
%
|
|
$
|
300
|
|
4.66
|
%
|
|
|
September 30, 2016
|
||
|
|
Aggregate Notional Amount
|
|
Weighted Average, LIBOR
|
Maturity Dates
|
|
(in millions)
|
|
Fixed Rate
|
March 15, 2018
|
|
$750
|
|
1.57%
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|||||||||||||
(In millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|||||||||
Cash Flow Hedges
|
|
|
|
|
|
|
|
|||||||||
Beginning balance
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Change in fair value recognized in other comprehensive income
|
2
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|||||
Reclassification from other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Ending balance
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
—
|
|
Crude Oil
|
|||||
|
2016
|
2017
|
|||
|
Fourth Quarter
|
First Quarter
|
Second Quarter
|
Third Quarter
|
Fourth Quarter
|
Three-Way Collars
(a)
|
|
||||
Volume (Bbls/day)
|
47,000
|
30,000
|
30,000
|
—
|
—
|
Price per Bbl:
|
|
|
|
|
|
Ceiling
|
$55.37
|
$58.19
|
$58.19
|
—
|
—
|
Floor
|
$50.23
|
$49.33
|
$49.33
|
—
|
—
|
Sold put
|
$40.96
|
$42.67
|
$42.67
|
—
|
—
|
Sold call options
(b)
|
|
|
|
|
|
Volume (Bbls/day)
|
10,000
|
35,000
|
35,000
|
35,000
|
35,000
|
Price per Bbl
|
$72.39
|
$61.91
|
$61.91
|
$61.91
|
$61.91
|
Two-way Collars
|
|
|
|
|
|
Volume (Bbls/day)
|
10,000
|
—
|
—
|
—
|
—
|
Price per Bbl:
|
|
|
|
|
|
Ceiling
|
$50.00
|
—
|
—
|
—
|
—
|
Floor
|
$41.55
|
—
|
—
|
—
|
—
|
(a)
|
Subsequent to September 30, 2016, we entered into
10,000
Bbls/day of three-way collars for January - June 2017 with a ceiling price of
$58.27
, a floor price of
$49.50
, and a sold put price of
$42.50
.
|
(b)
|
Call options settle monthly.
|
Natural Gas
|
|||||
|
2016
|
2017
|
|||
|
Fourth Quarter
|
First Quarter
|
Second Quarter
|
Third Quarter
|
Fourth Quarter
|
Three-Way Collars
(a)
|
|
|
|
|
|
Volume (MMBtu/day)
|
20,000
|
60,000
|
60,000
|
60,000
|
60,000
|
Price per MMBtu
|
|
|
|
|
|
Ceiling
|
$2.93
|
$3.46
|
$3.46
|
$3.46
|
$3.46
|
Floor
|
$2.50
|
$2.84
|
$2.84
|
$2.84
|
$2.84
|
Sold put
|
$2.00
|
$2.35
|
$2.35
|
$2.35
|
$2.35
|
(a)
|
On our 2016 collars, the counterparty has the option to execute fixed-price swaps (swaptions) at a weighted average price of
$2.93
per MMBtu indexed to NYMEX Henry Hub, which is exercisable on December 22, 2016. If the 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.
|
|
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
|
|
|
5,247,751
|
|
|
|
$7.93
|
|
Options Exercised/Stock Vested
|
—
|
|
|
—
|
|
|
(1,264,325
|
)
|
|
|
$32.52
|
|
|
Canceled
|
(1,936,084
|
)
|
|
|
$23.95
|
|
|
(1,119,975
|
)
|
|
|
$19.92
|
|
Outstanding at September 30, 2016
|
12,409,335
|
|
|
|
$27.83
|
|
|
6,880,795
|
|
|
|
$14.79
|
|
|
Nine Months Ended September 30,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
Net cash (used in) operating activities:
|
|
|
|
||||
Interest paid (net of amounts capitalized)
|
$
|
(243
|
)
|
|
$
|
(200
|
)
|
Income taxes paid to taxing authorities
|
(68
|
)
|
|
(174
|
)
|
||
Noncash investing activities:
|
|
|
|
|
|
||
Asset retirement cost increase
|
$
|
3
|
|
|
$
|
12
|
|
Asset retirement obligations assumed by buyer
|
86
|
|
|
23
|
|
•
|
Strengthened balance sheet
|
◦
|
At the end of the
third quarter
of 2016, we had
$5.3 billion
of liquidity, comprised of
$2.0 billion
in cash and an undrawn $3.3 billion revolving credit facility
|
◦
|
Cash-adjusted debt-to-capital ratio of
22%
at
September 30, 2016
, as compared with
25%
at December 31, 2015
|
•
|
Focused on cost reductions
|
◦
|
Decreased production expenses per boe in the
third quarter
of 2016, as compared to the same period last year in the North America E&P segment by 23% to
$5.70
per boe and in the International E&P segment by 27% to
$4.05
per boe
|
◦
|
Eagle Ford completed well costs were down to less than $4 million per well on average, which is a 20% decrease in the current quarter compared to the same quarter last year
|
◦
|
General and administrative expenses dropped $20 million versus the same quarter last year due to cost savings realized from the 2015 workforce reductions
|
•
|
Simplifying and concentrating portfolio
|
◦
|
In the quarter we closed on the Oklahoma STACK acquisition for
$904 million
, funded with cash on hand
|
◦
|
Closed the sale of non-operated CO2 and waterflood assets in West Texas and New Mexico for $235 million in late October, bringing our non-core asset sales announced or closed to more than $1.5 billion since August 2015
|
•
|
Operational updates
|
◦
|
Net sales volumes increased 78% in Oklahoma in the third quarter of 2016 compared to the same quarter last year; with Eagle Ford experiencing a 23% decrease over the same period
|
◦
|
Plan to increase North American E&P segment rig activity by 50% adding four rigs in the fourth quarter
|
◦
|
Net sales volumes in E.G. increased 14% in the third quarter of 2016 versus the same quarter last year due primarily to the completion of the Alba B3 compression project
|
•
|
Financial results
|
◦
|
Cash provided by operating activities of
$618 million
for the first nine months of 2016, reflecting average crude oil and condensate price realizations of $36.82 per bbl.
|
◦
|
Improving our net loss per share of
$0.23
in the
third quarter
of
2016
as compared to net loss per share of
$1.11
in the same period last year. Included in the third quarter 2016 net loss are:
|
▪
|
Expense associated with the termination payment for our Gulf of Mexico deepwater drilling rig of $113 million, pre-tax
|
▪
|
Unrealized gain on our commodity derivative instruments totaling
$25 million
, pre-tax
|
▪
|
Net gains on disposal of non-core assets totaling
$47 million
, pre-tax
|
▪
|
Non-cash charges totaling $
47 million
pre-tax, as a result of impairments of non-core proved properties
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
||||||||
Net Sales Volumes
|
2016
|
|
2015
|
|
Increase
(Decrease) |
|
2016
|
|
2015
|
|
Increase
(Decrease) |
North America E&P
(mboed)
|
216
|
|
261
|
|
(17)%
|
|
226
|
|
273
|
|
(17)%
|
International E&P
(mboed)
|
126
|
|
119
|
|
6%
|
|
114
|
|
115
|
|
(1)%
|
Oil Sands Mining
(mbbld)
(a)
|
65
|
|
65
|
|
—%
|
|
58
|
|
51
|
|
14%
|
Total
(mboed)
|
407
|
|
445
|
|
(9)%
|
|
398
|
|
439
|
|
(9)%
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
||||||||
Net Sales Volumes
|
2016
|
|
2015
|
|
Increase
(Decrease) |
|
2016
|
|
2015
|
|
Increase
(Decrease) |
Equivalent Barrels
(mboed)
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford
|
97
|
|
126
|
|
(23)%
|
|
109
|
|
137
|
|
(20)%
|
Oklahoma Resource Basins
|
41
|
|
23
|
|
78%
|
|
32
|
|
24
|
|
33%
|
Bakken
|
54
|
|
61
|
|
(11)%
|
|
55
|
|
59
|
|
(7)%
|
Other North America
(a)
|
24
|
|
51
|
|
(53)%
|
|
30
|
|
53
|
|
(43)%
|
Total North America E&P
|
216
|
|
261
|
|
(17)%
|
|
226
|
|
273
|
|
(17)%
|
|
Three Months Ended September 30, 2016
|
||||
Sales Mix - U.S. Resource Plays
|
Crude oil and condensate
|
|
Natural gas liquids
|
|
Natural gas
|
|
|
|
|
|
|
Eagle Ford
|
56%
|
|
23%
|
|
21%
|
Oklahoma Resource Basins
|
26%
|
|
26%
|
|
48%
|
Bakken
|
81%
|
|
11%
|
|
8%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Gross Operated
|
|
|
|
|
|
|
|
Eagle Ford:
|
|
|
|
|
|
|
|
Wells drilled to total depth
|
33
|
|
51
|
|
131
|
|
198
|
Wells brought to sales
|
36
|
|
57
|
|
116
|
|
200
|
Oklahoma Resource Basins:
|
|
|
|
|
|
|
|
Wells drilled to total depth
|
9
|
|
4
|
|
20
|
|
17
|
Wells brought to sales
|
12
|
|
8
|
|
20
|
|
16
|
Bakken:
|
|
|
|
|
|
|
|
Wells drilled to total depth
|
—
|
|
5
|
|
3
|
|
30
|
Wells brought to sales
|
3
|
|
5
|
|
13
|
|
51
|
•
|
Eagle Ford
– During the third quarter of 2016, we brought
36
gross operated wells to sales, of which 20 were Lower Eagle Ford, 15 were Upper Eagle Ford and 1 was Austin Chalk. Production decreases were in line with expectations and due to base declines and lower completion activity. We have plans to increase activity from four to six rigs in the fourth quarter.
|
•
|
Oklahoma Resource Basins
– Of the
12
gross operated wells brought to sales in the third quarter of 2016, 10 were in the STACK Meramec and 2 wells were in the SCOOP Woodford. Two of the STACK wells and one of the SCOOP wells were extended laterals. We also participated in 17 outside-operated wells during the third quarter of 2016, 9 of which were in the STACK and 8 were in the SCOOP.
|
•
|
Bakken
– Of the
3
gross operated wells brought to sales in the third quarter of 2016, 2 were in the Three Forks formation and 1 in the Middle Bakken formation. Strong well productivity from the Clarks Creek and Maggie pad along with high reliability continued to support base production in the current quarter. We plan to return to drilling in the Bakken with one rig to be added late in the fourth quarter.
|
•
|
Other North America
– Net sales volumes declined in the third quarter of 2016 primarily due to the aforementioned non-core asset sales.
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
||||||||
Net Sales Volumes
|
2016
|
|
2015
|
|
Increase
(Decrease)
|
|
2016
|
|
2015
|
|
Increase
(Decrease) |
Equivalent Barrels
(mboed)
|
|
|
|
|
|
|
|
|
|
|
|
Equatorial Guinea
|
115
|
|
101
|
|
14%
|
|
100
|
|
96
|
|
4%
|
United Kingdom
(a)
|
11
|
|
18
|
|
(39)%
|
|
14
|
|
19
|
|
(26)%
|
Total International E&P
|
126
|
|
119
|
|
6%
|
|
114
|
|
115
|
|
(1)%
|
Equity Method Investees
|
|
|
|
|
|
|
|
|
|
|
|
LNG
(mtd)
|
6,620
|
|
5,700
|
|
16%
|
|
5,584
|
|
5,653
|
|
(1)%
|
Methanol
(mtd)
|
1,529
|
|
1,125
|
|
36%
|
|
1,371
|
|
895
|
|
53%
|
Condensate & LPG
(boed)
|
16,766
|
|
13,427
|
|
25%
|
|
12,775
|
|
11,746
|
|
9%
|
(a)
|
Includes natural gas acquired for injection and subsequent resale of
5
mmcfd and
8
mmcfd for the
third quarter
s of
2016
and
2015
, and
5
mmcfd and
8
mmcfd for the first nine months of
2016
and
2015
.
|
•
|
Equatorial Guinea
– Third quarter 2016 net sales were higher compared to the same quarter of 2015 as a result of the completion and start-up of Alba field compression project, which achieved first gas in July. The project is expected to maintain the production plateau for an additional two years and extend field life up to eight years.
|
•
|
United Kingdom
– Net sales volumes in the first nine months of 2016 were lower due to the timing of Brae liftings and repair activities at the Brae Alpha facility following a process pipe failure in late 2015. Production was restored at the facility in late April. Higher overall production efficiency at the remaining Brae facilities and improved reliability from the outside-operated Foinaven field partially offset the Brae Alpha outage.
|
•
|
Libya
– Force Majeure was lifted on September 14, 2016 and production resumed on October 2, 2016 at our Waha concession. The Libya National Oil Corporation has commenced lifting from the Ras Lanuf crude oil terminal and liftings from the Es-Sider terminal may resume as early as the fourth quarter of 2016.
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|||||||||||||
|
2016
|
|
2015
|
|
Decrease
|
|
2016
|
|
2015
|
|
Increase (Decrease)
|
|||||
Average Price Realizations
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Crude Oil and Condensate
(per bbl)
(b)
|
$41.35
|
|
$41.37
|
|
—%
|
|
$36.37
|
|
$45.27
|
|
(20
|
)%
|
||||
Natural Gas Liquids
(per bbl)
|
12.44
|
|
11.88
|
|
5%
|
|
11.79
|
|
|
13.67
|
|
|
(14
|
)%
|
||
Total Liquid Hydrocarbons
(per bbl)
|
34.00
|
|
35.75
|
|
(5)%
|
|
30.79
|
|
|
39.55
|
|
|
(22
|
)%
|
||
Natural Gas
(per mcf)
|
2.67
|
|
2.75
|
|
(3)%
|
|
2.22
|
|
|
2.84
|
|
|
(22
|
)%
|
||
Benchmarks
|
|
|
|
|
|
|
|
|
|
|
|
|||||
WTI crude oil
(per bbl)
|
$44.94
|
|
$46.50
|
|
(3)%
|
|
|
$41.53
|
|
|
|
$51.01
|
|
|
(19
|
)%
|
LLS crude oil
(per bbl)
|
46.52
|
|
50.22
|
|
(7)%
|
|
43.19
|
|
|
55.33
|
|
|
(22
|
)%
|
||
Mont Belvieu NGLs
(per bbl)
(c)
|
17.04
|
|
15.86
|
|
7%
|
|
16.21
|
|
|
17.28
|
|
|
(6
|
)%
|
||
Henry Hub natural gas
(per mmbtu)
|
2.81
|
|
2.77
|
|
1%
|
|
2.29
|
|
|
2.80
|
|
|
(18
|
)%
|
(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
$1.55
per bbl and
$1.87
per bbl for the
third quarter
2016
and
2015
, and
$1.10
per bbl and
$0.69
per bbl for the first nine months of
2016
and
2015
.
|
(c)
|
Bloomberg Finance LLP: Y-grade Mix NGL of 50% ethane, 25% propane, 10% butane, 5% isobutane and 10% natural gasoline.
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|||||||||||||
|
2016
|
|
2015
|
|
Increase
(Decrease) |
|
2016
|
|
2015
|
|
Increase
(Decrease) |
|||||
Average Price Realizations
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Crude Oil and Condensate (
per bbl
)
|
$41.45
|
|
$46.18
|
|
(10)%
|
|
$38.99
|
|
$50.51
|
|
(23
|
)%
|
||||
Natural Gas Liquids (
per bbl
)
|
1.93
|
|
2.69
|
|
(28)%
|
|
2.25
|
|
|
3.08
|
|
|
(27
|
)%
|
||
Liquid Hydrocarbons (
per bbl
)
|
30.40
|
|
35.88
|
|
(15)%
|
|
28.96
|
|
|
39.21
|
|
|
(26
|
)%
|
||
Natural Gas (
per mcf
)
|
0.46
|
|
0.59
|
|
(22)%
|
|
0.52
|
|
|
0.71
|
|
|
(27
|
)%
|
||
Benchmark
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Brent (Europe) crude oil (
per bbl
)
(a)
|
$45.79
|
|
$50.23
|
|
(9%)
|
|
|
$41.67
|
|
|
|
$55.28
|
|
|
(25
|
)%
|
(a)
|
Average of monthly prices obtained from EIA website.
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|||||||||||||
|
2016
|
|
2015
|
|
Decrease
|
|
2016
|
|
2015
|
|
Increase (Decrease)
|
|||||
Average Price Realizations
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Synthetic Crude Oil
(per bbl)
|
$39.59
|
|
$39.49
|
|
—%
|
|
|
$35.46
|
|
|
|
$42.26
|
|
|
(16
|
%)
|
Benchmarks
|
|
|
|
|
|
|
|
|
|
|
|
|||||
WTI crude oil
(per bbl)
|
$44.94
|
|
$46.50
|
|
(3%)
|
|
|
$41.53
|
|
|
|
$51.01
|
|
|
(19
|
%)
|
WCS crude oil
(per bbl)
(a)
|
31.44
|
|
33.16
|
|
(5%)
|
|
27.65
|
|
|
37.80
|
|
|
(27
|
%)
|
(a)
|
Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.
|
|
Three Months Ended September 30,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
Sales and other operating revenues, including related party
|
|
|
|
||||
North America E&P
|
$
|
604
|
|
|
$
|
796
|
|
International E&P
|
152
|
|
|
182
|
|
||
Oil Sands Mining
|
239
|
|
|
242
|
|
||
Segment sales and other operating revenues, including related party
|
$
|
995
|
|
|
$
|
1,220
|
|
Unrealized gain on commodity derivative instruments
|
25
|
|
|
80
|
|
||
Sales and other operating revenues, including related party
|
$
|
1,020
|
|
|
$
|
1,300
|
|
(a)
|
Three months ended September 30, 2016 includes a net sales volume reduction of 30 mboed related to dispositions in the Gulf of Mexico and other conventional onshore U.S. production.
|
|
Three Months Ended September 30,
|
||||||
($ per boe)
|
2016
|
|
2015
|
||||
Production Expense Rate
|
|
|
|
||||
North America E&P
|
|
$5.70
|
|
|
|
$7.43
|
|
International E&P
|
|
$4.05
|
|
|
|
$5.53
|
|
Oil Sands Mining
(a)
|
|
$20.69
|
|
|
|
$26.01
|
|
|
Three Months Ended September 30,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
Exploration Expenses
|
|
|
|
||||
Unproved property impairments
|
$
|
28
|
|
|
$
|
563
|
|
Dry well costs
|
9
|
|
|
(3
|
)
|
||
Geological and geophysical
|
1
|
|
|
8
|
|
||
Other
|
45
|
|
|
17
|
|
||
Total exploration expenses
|
$
|
83
|
|
|
$
|
585
|
|
|
Three Months Ended September 30,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
Production and severance
|
$
|
23
|
|
|
$
|
28
|
|
Ad valorem
|
3
|
|
|
2
|
|
||
Other
|
13
|
|
|
16
|
|
||
Total
|
$
|
39
|
|
|
$
|
46
|
|
|
Three Months Ended September 30,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
North America E&P
|
$
|
(59
|
)
|
|
$
|
(61
|
)
|
International E&P
|
59
|
|
|
29
|
|
||
Oil Sands Mining
|
15
|
|
|
(11
|
)
|
||
Segment income (loss)
|
15
|
|
|
(43
|
)
|
||
Items not allocated to segments, net of income taxes
|
(207
|
)
|
|
(706
|
)
|
||
Net income (loss)
|
$
|
(192
|
)
|
|
$
|
(749
|
)
|
|
Nine Months Ended September 30,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
Sales and other operating revenues, including related party
|
|
|
|
||||
North America E&P
|
$
|
1,714
|
|
|
$
|
2,639
|
|
International E&P
|
407
|
|
|
575
|
|
||
Oil Sands Mining
|
572
|
|
|
614
|
|
||
Segment sales and other operating revenues, including related party
|
$
|
2,693
|
|
|
$
|
3,828
|
|
Unrealized gain (loss) on commodity derivative instruments
|
(89
|
)
|
|
59
|
|
||
Sales and other operating revenues, including related party
|
$
|
2,604
|
|
|
$
|
3,887
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
Increase (Decrease) Related to
|
|
Nine Months Ended
|
||||||||||
(In millions)
|
|
September 30, 2015
|
|
Price Realizations
|
|
Net Sales Volumes
|
|
September 30, 2016
|
||||||||
North America E&P Price-Volume Analysis (a)
|
||||||||||||||||
Liquid hydrocarbons
|
|
$
|
2,307
|
|
|
$
|
(419
|
)
|
|
$
|
(420
|
)
|
|
$
|
1,468
|
|
Natural gas
|
|
273
|
|
|
(53
|
)
|
|
(29
|
)
|
|
191
|
|
||||
Realized gain on commodity
|
|
|
|
|
|
|
|
|
||||||||
derivative instruments
|
|
33
|
|
|
8
|
|
|
|
|
41
|
|
|||||
Other sales
|
|
26
|
|
|
|
|
|
|
14
|
|
||||||
Total
|
|
$
|
2,639
|
|
|
|
|
|
|
$
|
1,714
|
|
||||
International E&P Price-Volume Analysis
|
||||||||||||||||
Crude oil and condensate
|
|
|
|
|
|
|
|
|
||||||||
Natural gas liquids
|
|
|
|
|
|
|
|
|
||||||||
Liquid hydrocarbons
|
|
$
|
462
|
|
|
$
|
(113
|
)
|
|
$
|
(30
|
)
|
|
$
|
319
|
|
Natural gas
|
|
83
|
|
|
(23
|
)
|
|
3
|
|
|
63
|
|
||||
Other sales
|
|
30
|
|
|
|
|
|
|
25
|
|
||||||
Total
|
|
$
|
575
|
|
|
|
|
|
|
$
|
407
|
|
||||
Oil Sands Mining Price-Volume Analysis
|
||||||||||||||||
Synthetic crude oil
|
|
$
|
592
|
|
|
$
|
(108
|
)
|
|
$
|
77
|
|
|
$
|
562
|
|
Other sales
|
|
22
|
|
|
|
|
|
|
10
|
|
||||||
Total
|
|
$
|
614
|
|
|
|
|
|
|
$
|
572
|
|
|
Nine Months Ended September 30,
|
||||||
($ per boe)
|
2016
|
|
2015
|
||||
Production Expense Rate
|
|
|
|
||||
North America E&P
|
|
$6.06
|
|
|
|
$7.52
|
|
International E&P
|
|
$4.98
|
|
|
|
$6.13
|
|
Oil Sands Mining
(a)
|
|
$28.35
|
|
|
|
$39.58
|
|
(a)
|
Production expense per synthetic crude oil barrel includes production costs, shipping and handling, taxes other than income and insurance costs and excludes pre-development costs.
|
|
Nine Months Ended September 30,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
Exploration Expenses
|
|
|
|
||||
Unproved property impairments
|
$
|
172
|
|
|
$
|
612
|
|
Dry well costs
|
31
|
|
|
96
|
|
||
Geological and geophysical
|
1
|
|
|
23
|
|
||
Other
|
92
|
|
|
55
|
|
||
Total exploration expenses
|
$
|
296
|
|
|
$
|
786
|
|
|
Nine Months Ended September 30,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
Production and severance
|
$
|
68
|
|
|
$
|
102
|
|
Ad valorem
|
22
|
|
|
33
|
|
||
Other
|
36
|
|
|
56
|
|
||
Total
|
$
|
126
|
|
|
$
|
191
|
|
|
Nine Months Ended September 30,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
North America E&P
|
$
|
(324
|
)
|
|
$
|
(267
|
)
|
International E&P
|
118
|
|
|
93
|
|
||
Oil Sands Mining
|
(71
|
)
|
|
(107
|
)
|
||
Segment income (loss)
|
(277
|
)
|
|
(281
|
)
|
||
Items not allocated to segments, net of income taxes
|
(492
|
)
|
|
(1,130
|
)
|
||
Net income (loss)
|
$
|
(769
|
)
|
|
$
|
(1,411
|
)
|
|
Unweighted 11-month 2016 Average
|
Unweighted 12-month 2015 Average
|
WTI Crude oil
|
$41.99
|
$50.28
|
Henry Hub natural gas
|
2.41
|
2.59
|
Brent crude oil
|
42.67
|
54.25
|
Natural gas liquids
|
15.58
|
17.32
|
|
Nine Months Ended September 30,
|
|||||
(In millions)
|
2016
|
2015
|
||||
Sources of cash and cash equivalents
|
|
|
|
|
||
Operating activities
|
$
|
618
|
|
$
|
1,213
|
|
Disposals of assets
|
837
|
|
105
|
|
||
Borrowings
|
—
|
|
1,996
|
|
||
Common stock issuance
|
1,236
|
|
—
|
|
||
Maturities of short-term investment
|
—
|
|
225
|
|
||
Other
|
49
|
|
97
|
|
||
Total sources of cash and cash equivalents
|
$
|
2,740
|
|
$
|
3,636
|
|
Uses of cash and cash equivalents
|
|
|
||||
Cash additions to property, plant and equipment
|
$
|
(983
|
)
|
$
|
(2,948
|
)
|
Acquisitions, net of cash acquired
|
(902
|
)
|
—
|
|
||
Purchases of short-term investments
|
—
|
|
(925
|
)
|
||
Debt issuance costs
|
—
|
|
(19
|
)
|
||
Debt repayments
|
(1
|
)
|
(34
|
)
|
||
Dividends paid
|
(119
|
)
|
(427
|
)
|
||
Other
|
(3
|
)
|
(1
|
)
|
||
Total uses of cash and cash equivalents
|
$
|
(2,008
|
)
|
$
|
(4,354
|
)
|
|
Nine Months Ended September 30,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
North America E&P
|
$
|
684
|
|
|
$
|
2,048
|
|
International E&P
|
62
|
|
|
275
|
|
||
Oil Sands Mining
|
28
|
|
|
26
|
|
||
Corporate
|
11
|
|
|
26
|
|
||
Total capital expenditures
|
785
|
|
|
2,375
|
|
||
Decrease in capital expenditure accrual
|
198
|
|
|
573
|
|
||
Total use of cash and cash equivalents for property, plant and equipment
|
$
|
983
|
|
|
$
|
2,948
|
|
|
September 30,
|
|
December 31,
|
||||
(In millions)
|
2016
|
|
2015
|
||||
Long-term debt due within one year
|
$
|
1
|
|
|
$
|
1
|
|
Long-term debt
|
7,277
|
|
|
7,276
|
|
||
Total debt
|
$
|
7,278
|
|
|
$
|
7,277
|
|
Cash and cash equivalents
|
$
|
1,953
|
|
|
$
|
1,221
|
|
Equity
|
$
|
18,922
|
|
|
$
|
18,553
|
|
Calculation:
|
|
|
|
|
|
||
Total debt
|
$
|
7,278
|
|
|
$
|
7,277
|
|
Minus cash and cash equivalents
|
1,953
|
|
|
1,221
|
|
||
Total debt minus cash, cash equivalents
|
$
|
5,325
|
|
|
$
|
6,056
|
|
Total debt
|
$
|
7,278
|
|
|
$
|
7,277
|
|
Plus equity
|
18,922
|
|
|
18,553
|
|
||
Minus cash and cash equivalents
|
1,953
|
|
|
1,221
|
|
||
Total debt plus equity minus cash, cash equivalents
|
$
|
24,247
|
|
|
$
|
24,609
|
|
Cash-adjusted debt-to-capital ratio
|
22
|
%
|
|
25
|
%
|
•
|
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 economic conditions in the jurisdictions in which we operate, including changes in foreign currency exchange rates, interest rates, inflation rates, and global and domestic market conditions;
|
•
|
capital available for exploration and development;
|
•
|
risks related to our hedging activities;
|
•
|
our level of success in integrating acquisitions;
|
•
|
well production timing;
|
•
|
drilling and operating risks;
|
•
|
availability of materials and labor;
|
•
|
difficulty in obtaining necessary approvals and permits;
|
•
|
non-performance by third parties of contractual obligations;
|
•
|
unforeseen hazards such as weather conditions;
|
•
|
political conditions and developments, including political instability, acts of war or terrorist acts, and the governmental or military response thereto;
|
•
|
cyber-attacks;
|
•
|
changes in safety, health, environmental, tax and other regulations;
|
•
|
other geological, operating and economic considerations; and
|
•
|
the risk factors, forward-looking statements and challenges and uncertainties described in our 2015 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other filings with the SEC.
|
Crude Oil
|
|||||
|
2016
|
2017
|
|||
|
Fourth Quarter
|
First Quarter
|
Second Quarter
|
Third Quarter
|
Fourth Quarter
|
Three-Way Collars
(a)
|
|
||||
Volume (Bbls/day)
|
47,000
|
30,000
|
30,000
|
—
|
—
|
Price per Bbl:
|
|
|
|
|
|
Ceiling
|
$55.37
|
$58.19
|
$58.19
|
—
|
—
|
Floor
|
$50.23
|
$49.33
|
$49.33
|
—
|
—
|
Sold put
|
$40.96
|
$42.67
|
$42.67
|
—
|
—
|
Sold call options
(b)
|
|
|
|
|
|
Volume (Bbls/day)
|
10,000
|
35,000
|
35,000
|
35,000
|
35,000
|
Price per Bbl
|
$72.39
|
$61.91
|
$61.91
|
$61.91
|
$61.91
|
Two-way Collars
|
|
|
|
|
|
Volume (Bbls/day)
|
10,000
|
—
|
—
|
—
|
—
|
Price per Bbl:
|
|
|
|
|
|
Ceiling
|
$50.00
|
—
|
—
|
—
|
—
|
Floor
|
$41.55
|
—
|
—
|
—
|
—
|
(a)
|
Subsequent to September 30, 2016, we entered into 10,000 Bbls/day of three-way collars for January - June 2017 with a ceiling price of $58.27, a floor price of $49.50, and a sold put price of $42.50.
|
(b)
|
Call options settle monthly.
|
Natural Gas
|
|||||
|
2016
|
2017
|
|||
|
Fourth Quarter
|
First Quarter
|
Second Quarter
|
Third Quarter
|
Fourth Quarter
|
Three-Way Collars
(a)
|
|
|
|
|
|
Volume (MMBtu/day)
|
20,000
|
60,000
|
60,000
|
60,000
|
60,000
|
Price per MMBtu
|
|
|
|
|
|
Ceiling
|
$2.93
|
$3.46
|
$3.46
|
$3.46
|
$3.46
|
Floor
|
$2.50
|
$2.84
|
$2.84
|
$2.84
|
$2.84
|
Sold put
|
$2.00
|
$2.35
|
$2.35
|
$2.35
|
$2.35
|
(a)
|
On our 2016 collars, the counterparty has the option to execute fixed-price swaps (swaptions) at a weighted average price of
$2.93
per MMBtu indexed to NYMEX Henry Hub, which is exercisable on December 22, 2016. If counterparty exercises, the term of the fixed-price swaps would be for the calendar year 2017 and, if all such options are exercised,
20,000
MMBtu per day.
|
(In millions)
|
Hypothetical Price Increase of 10%
|
Hypothetical Price Decrease of 10%
|
||||
|
|
|
||||
Crude oil derivatives
|
$
|
(59
|
)
|
$
|
46
|
|
Natural gas derivatives
|
(6
|
)
|
5
|
|
||
Total
|
$
|
(65
|
)
|
$
|
51
|
|
(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.
|
|
Total Number of
|
|
Average Price
|
|
Total Number of
Shares Purchased
as Part of
Publicly Announced
|
|
Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
|
||
Period
|
Shares Purchased
(a)
|
|
Paid per Share
|
|
Plans or Programs
|
|
Plans or Programs
|
||
07/01/16 - 07/31/16
|
3,468
|
|
|
$15.16
|
|
—
|
|
|
n/a
|
08/01/16 - 08/31/16
|
39,245
|
|
|
$14.89
|
|
—
|
|
|
n/a
|
09/01/16 - 09/30/16
|
2,352
|
|
|
$14.61
|
|
—
|
|
|
n/a
|
Total
|
45,065
|
|
|
$14.89
|
|
—
|
|
|
|
(a)
|
45,065
shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.
|
November 3, 2016
|
|
MARATHON OIL CORPORATION
|
|
|
|
|
By:
|
/s/ Gary E. Wilson
|
|
|
Gary E. Wilson
|
|
|
Vice President, Controller and Chief Accounting Officer
|
|
|
(Duly Authorized Officer)
|
|
|
|
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)*
|
|
|
|
|
|
|
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
|
|
10.1
|
|
Marathon Oil Corporation 2016 Incentive Compensation Plan
|
14A
|
|
App. A
|
|
4/07/2016
|
|
10.2
|
|
Separation Agreement with John R. Sult
|
8-K
|
|
10.1
|
|
9/23/2016
|
|
10.3
|
|
Consulting Services Agreement with John R. Sult
|
8-K
|
|
10.2
|
|
9/23/2016
|
|
10.4
|
|
Separation Agreement with Lance W. Robertson
|
8-K
|
|
10.3
|
|
9/23/2016
|
|
10.5
|
|
Form of Restricted Stock Award Agreement for Section 16 Reporting Officers granted under the Marathon Oil Corporation 2016 Incentive Compensation Plan
|
8-K/A
|
|
10.1
|
|
9/30/2016
|
|
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.
|
|
|
|
|
|
|
1 Year Marathon Oil Chart |
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