mro10-q09302008.htm
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
(Mark
One)
|
|
[X]
|
QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d)
OF
THE SECURITIES EXCHANGE ACT OF 1934
|
|
For
the Quarterly Period Ended September 30,
2008
|
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 Road, 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 ü 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 ü
|
Accelerated
filer
|
Non-accelerated
filer (Do
not check if a smaller reporting company)
|
Smaller
reporting company ü
|
Indicate by check mark whether the
registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). Yes No ü
There
were 705,576,258 shares of Marathon Oil Corporation common stock outstanding as
of October 31, 2008.
MARATHON
OIL CORPORATION
Form
10-Q
Quarter
Ended September 30, 2008
|
INDEX
|
|
|
Page
|
PART
I - FINANCIAL INFORMATION
|
Item
1.
|
Financial
Statements:
|
|
|
Consolidated
Statements of Income (Unaudited)
|
2
|
|
Consolidated
Balance Sheets (Unaudited)
|
3
|
|
Consolidated
Statements of Cash Flows (Unaudited)
|
4
|
|
Notes
to Consolidated Financial Statements (Unaudited)
|
5
|
Item
2.
|
Management's
Discussion and Analysis of Financial Condition and Results of
Operations
|
17
|
Item
3.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
29
|
Item
4.
|
Controls
and Procedures
|
32
|
|
Supplemental
Statistics
|
33
|
PART
II - OTHER INFORMATION
|
Item
1.
|
Legal
Proceedings
|
35
|
Item
1A.
|
Risk
Factors
|
36
|
Item
2.
|
Unregistered
Sales of Equity Securities and Use of Proceeds
|
36
|
Item
6.
|
Exhibits
|
37
|
|
Signatures
|
38
|
Unless
the context otherwise indicates, references in this Form 10-Q to “Marathon,”
“we,” “our,” or “us” 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 exerts significant influence by
virtue of its ownership interest).
Part I -
Financial Information
Item
1. Financial Statements
MARATHON
OIL CORPORATION
Consolidated
Statements of Income (Unaudited)
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
September
30,
|
|
September
30,
|
|
(In
millions, except per share data)
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
Revenues
and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
and other operating revenues (including
|
$
|
22,477
|
|
$
|
16,347
|
|
$
|
60,983
|
|
$
|
45,221
|
|
consumer
excise taxes)
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
to related parties
|
|
637
|
|
|
415
|
|
|
1,865
|
|
|
1,146
|
|
Income
from equity method investments
|
|
270
|
|
|
170
|
|
|
735
|
|
|
394
|
|
Net
gain on disposal of assets
|
|
15
|
|
|
2
|
|
|
37
|
|
|
20
|
|
Other
income
|
|
47
|
|
|
20
|
|
|
151
|
|
|
62
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
revenues and other income
|
|
23,446
|
|
|
16,954
|
|
|
63,771
|
|
|
46,843
|
|
Costs
and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of revenues (excludes items below)
|
|
16,992
|
|
|
12,951
|
|
|
49,432
|
|
|
34,358
|
|
Purchases
from related parties
|
|
244
|
|
|
104
|
|
|
609
|
|
|
240
|
|
Consumer
excise taxes
|
|
1,273
|
|
|
1,352
|
|
|
3,784
|
|
|
3,856
|
|
Depreciation,
depletion and amortization
|
|
597
|
|
|
409
|
|
|
1,552
|
|
|
1,198
|
|
Selling,
general and administrative expenses
|
|
351
|
|
|
336
|
|
|
1,012
|
|
|
950
|
|
Other
taxes
|
|
126
|
|
|
95
|
|
|
376
|
|
|
286
|
|
Exploration
expenses
|
|
109
|
|
|
88
|
|
|
368
|
|
|
264
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
costs and expenses
|
|
19,692
|
|
|
15,335
|
|
|
57,133
|
|
|
41,152
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from operations
|
|
3,754
|
|
|
1,619
|
|
|
6,638
|
|
|
5,691
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
interest and other financing income (costs)
|
|
(53)
|
|
|
19
|
|
|
(54)
|
|
|
58
|
|
Gain
on foreign currency derivative instruments
|
|
-
|
|
|
120
|
|
|
-
|
|
|
120
|
|
Loss
on early extinguishment of debt
|
|
-
|
|
|
(11)
|
|
|
-
|
|
|
(14)
|
|
Minority
interests in loss of Equatorial Guinea
|
|
|
|
|
|
|
|
|
|
|
|
|
LNG
Holdings Limited
|
|
-
|
|
|
-
|
|
|
-
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from continuing operations before
|
|
|
|
|
|
|
|
|
|
|
|
|
income
taxes
|
|
3,701
|
|
|
1,747
|
|
|
6,584
|
|
|
5,858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for income taxes
|
|
1,637
|
|
|
726
|
|
|
3,015
|
|
|
2,578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from continuing operations
|
|
2,064
|
|
|
1,021
|
|
|
3,569
|
|
|
3,280
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued
operations
|
|
-
|
|
|
-
|
|
|
-
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
$
|
2,064
|
|
$
|
1,021
|
|
$
|
3,569
|
|
$
|
3,288
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per
Share Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from continuing operations
|
$
|
2.92
|
|
$
|
1.50
|
|
$
|
5.03
|
|
$
|
4.80
|
|
Discontinued
operations
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
0.01
|
|
Net
income
|
$
|
2.92
|
|
$
|
1.50
|
|
$
|
5.03
|
|
$
|
4.81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from continuing operations
|
$
|
2.90
|
|
$
|
1.49
|
|
$
|
5.00
|
|
$
|
4.76
|
|
Discontinued
operations
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
0.01
|
|
Net
income
|
$
|
2.90
|
|
$
|
1.49
|
|
$
|
5.00
|
|
$
|
4.77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
|
$
|
0.24
|
|
$
|
0.24
|
|
$
|
0.72
|
|
$
|
0.68
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
|
MARATHON
OIL CORPORATION
Consolidated
Balance Sheets (Unaudited)
|
|
September
30,
|
|
December
31,
|
|
(In
millions, except per share data)
|
2008
|
2007
|
|
Assets
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
$
|
1,479
|
|
$
|
1,199
|
|
Receivables,
less allowance for doubtful accounts of $4 and $3
|
|
6,094
|
|
|
5,818
|
|
Receivables
from United States Steel
|
|
23
|
|
|
22
|
|
Receivables
from related parties
|
|
115
|
|
|
79
|
|
Inventories
|
|
4,446
|
|
|
3,277
|
|
Other
current assets
|
|
216
|
|
|
192
|
|
|
|
|
|
|
|
|
Total
current assets
|
|
12,373
|
|
|
10,587
|
|
|
|
|
|
|
|
|
Equity
method investments
|
|
2,827
|
|
|
2,630
|
|
Receivables
from United States Steel
|
|
469
|
|
|
485
|
|
Property,
plant and equipment, less accumulated depreciation,
|
|
|
|
|
|
|
depletion
and amortization of $16,152 and $14,857
|
28,129
|
24,675
|
|
Goodwill
|
|
2,887
|
|
|
2,899
|
|
Intangible
assets, less accumulated amortization of $93 and $80
|
|
279
|
|
|
288
|
|
Other
noncurrent assets
|
|
1,942
|
|
|
1,182
|
|
|
|
|
|
|
|
|
Total
assets
|
$
|
48,906
|
|
$
|
42,746
|
|
Liabilities
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
Short-term debt
|
$
|
1,290
|
|
$
|
-
|
|
Accounts
payable and accrued liabilities
|
|
8,975
|
|
|
8,281
|
|
Payables
to related parties
|
|
40
|
|
|
44
|
|
Payroll
and benefits payable
|
|
364
|
|
|
417
|
|
Accrued
taxes
|
|
992
|
|
|
712
|
|
Deferred
income taxes
|
|
397
|
|
|
547
|
|
Accrued
interest
|
|
131
|
|
|
128
|
|
Long-term
debt due within one year
|
|
88
|
|
|
1,131
|
|
|
|
|
|
|
|
|
Total
current liabilities
|
|
12,277
|
|
|
11,260
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
7,074
|
|
|
6,084
|
|
Deferred
income taxes
|
|
4,873
|
|
|
3,389
|
|
Defined
benefit postretirement plan obligations
|
|
1,205
|
|
|
1,092
|
|
Asset
retirement obligations
|
|
1,135
|
|
|
1,131
|
|
Payable
to United States Steel
|
|
4
|
|
|
5
|
|
Deferred
credits and other liabilities
|
|
411
|
|
|
562
|
|
|
|
|
|
|
|
|
Total
liabilities
|
|
26,979
|
|
|
23,523
|
|
|
|
|
|
|
|
|
Commitments
and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders’
Equity
|
|
|
|
|
|
|
Preferred
stock – 5 million shares issued, 3 million and 5 million
shares
|
|
|
|
|
|
|
outstanding
(no par value, 6 million shares authorized)
|
|
-
|
|
|
-
|
|
Common
stock:
|
|
|
|
|
|
|
Issued
– 767 million and 765 million shares (par value $1 per
share,
|
|
|
|
|
|
|
1.1
billion shares authorized)
|
767
|
765
|
|
Securities
exchangeable into common stock – 5 million shares issued,
|
|
|
|
|
|
|
3
million and 5 million shares outstanding (no par value,
unlimited
|
|
|
|
|
|
|
shares
authorized)
|
|
-
|
|
|
-
|
|
Held
in treasury, at cost – 61 million and 55 million shares
|
|
(2,722)
|
|
|
(2,384)
|
|
Additional
paid-in capital
|
|
6,686
|
|
|
6,679
|
|
Retained
earnings
|
|
17,470
|
|
|
14,412
|
|
Accumulated
other comprehensive loss
|
|
(274)
|
|
|
(249)
|
|
|
|
|
|
|
|
|
Total
stockholders' equity
|
|
21,927
|
|
|
19,223
|
|
|
|
|
|
|
|
|
Total
liabilities and stockholders' equity
|
$
|
48,906
|
|
$
|
42,746
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
|
MARATHON
OIL CORPORATION
Consolidated
Statements of Cash Flows (Unaudited)
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
|
September
30,
|
|
(In
millions)
|
2008
|
|
2007
|
|
Increase
(decrease) in cash and cash equivalents
|
|
|
|
|
|
|
Operating
activities:
|
|
|
|
|
|
|
Net
income
|
$
|
3,569
|
|
$
|
3,288
|
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
|
|
|
|
|
|
Loss
on early extinguishment of debt
|
|
-
|
|
|
14
|
|
Income
from discontinued operations
|
|
-
|
|
|
(8)
|
|
Deferred
income taxes
|
|
314
|
|
|
12
|
|
Minority
interests in loss of Equatorial Guinea LNG Holdings
Limited
|
|
-
|
|
|
(3)
|
|
Depreciation,
depletion and amortization
|
|
1,552
|
|
|
1,198
|
|
Pension
and other postretirement benefits, net
|
|
115
|
|
|
68
|
|
Exploratory
dry well costs and unproved property impairments
|
|
154
|
|
|
109
|
|
Net
gain on disposal of assets
|
|
(37)
|
|
|
(20)
|
|
Equity
method investments, net
|
|
(139)
|
|
|
(123)
|
|
Changes
in the fair value of U.K. natural gas contracts
|
|
37
|
|
|
111
|
|
Changes
in:
|
|
|
|
|
|
|
Current
receivables
|
|
(287)
|
|
|
(1,190)
|
|
Inventories
|
|
(1,173)
|
|
|
(1,444)
|
|
Current
accounts payable and accrued liabilities
|
|
703
|
|
|
988
|
|
All
other, net
|
|
(1)
|
|
|
(49)
|
|
Net
cash provided by operating activities
|
|
4,807
|
|
|
2,951
|
|
Investing
activities:
|
|
|
|
|
|
|
Capital
expenditures
|
|
(5,168)
|
|
|
(2,725)
|
|
Disposal
of assets
|
|
68
|
|
|
51
|
|
Trusteed
funds - withdrawals
|
|
402
|
|
|
163
|
|
Investments
- loans and advances
|
|
(104)
|
|
|
(88)
|
|
Investments
- repayments of loans and return of capital
|
|
18
|
|
|
35
|
|
Deconsolidation
of Equatorial Guinea LNG Holdings Limited
|
|
-
|
|
|
(37)
|
|
All
other, net
|
|
(16)
|
|
|
(8)
|
|
Net
cash used in investing activities
|
|
(4,800)
|
|
|
(2,609)
|
|
Financing
activities:
|
|
|
|
|
|
|
Short
term debt, net
|
|
1,288
|
|
|
-
|
|
Borrowings
|
|
1,248
|
|
|
2,071
|
|
Debt
issuance costs
|
|
(7)
|
|
|
(19)
|
|
Debt
repayments
|
|
(1,331)
|
|
|
(541)
|
|
Issuance
of common stock
|
|
9
|
|
|
23
|
|
Purchases
of common stock
|
|
(402)
|
|
|
(800)
|
|
Excess
tax benefits from stock-based compensation arrangements
|
|
8
|
|
|
25
|
|
Dividends
paid
|
|
(511)
|
|
|
(465)
|
|
Contributions
from minority shareholders of Equatorial Guinea LNG Holdings
Limited
|
|
-
|
|
|
39
|
|
Net
cash provided by financing activities
|
|
302
|
|
|
333
|
|
Effect
of exchange rate changes on cash
|
|
(29)
|
|
|
9
|
|
Net
increase in cash and cash equivalents
|
|
280
|
|
|
684
|
|
Cash
and cash equivalents at beginning of period
|
|
1,199
|
|
|
2,585
|
|
Cash
and cash equivalents at end of period
|
$
|
1,479
|
|
$
|
3,269
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
|
MARATHON
OIL CORPORATION
Notes
to Consolidated Financial Statements (Unaudited)
1. Basis
of Presentation
These
consolidated financial statements are unaudited but, in the opinion of
management, 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 Securities and Exchange Commission
and do not include all of the information and disclosures required by accounting
principles generally accepted in the United States of America for complete
financial statements. Certain reclassifications of prior year data
have been made to conform to 2008 classifications. These interim
financial statements should be read in conjunction with the consolidated
financial statements and notes thereto included in the Marathon Oil Corporation
(“Marathon” or the “Company”) 2007 Annual Report on Form 10-K. The
results of operations for the quarter and nine-months ended September 30, 2008
are not necessarily indicative of the results to be expected for the full
year.
2. New
Accounting Standards
In
April 2007, the Financial Accounting Standards Board (“FASB”) issued FASB Staff
Position (“FSP”) FASB Interpretation No. 39 (“FSP FIN 39-1”),
“Offsetting of Amounts Related to Certain Contracts”, which allows a
party to a master netting agreement to offset the fair value amounts related to
the right to reclaim collateral against the fair value amounts recognized for
derivative instruments. Such treatment was consistent with Marathon’s
accounting policy; therefore, adoption of FSP FIN No. 39-1 effective January 1,
2008, did not have any effect on our consolidated financial
position.
In
February 2007, the FASB issued Statement of Financial Accounting Standards
(“SFAS”) No. 159, “The Fair Value Option for Financial Assets and Financial
Liabilities.” This statement permits entities to choose to measure at
fair value many financial instruments and certain other items that are not
currently required to be measured at fair value. It requires that
unrealized gains and losses on items for which the fair value option has been
elected be recorded in net income. The statement also establishes
presentation and disclosure requirements designed to facilitate comparisons
between entities that choose different measurement attributes for similar types
of assets and liabilities. We did not elect the fair value option
when this standard became effective on January 1, 2008.
In
September 2006, the FASB issued SFAS No. 157, “Fair Value
Measurements.” This statement defines fair value, establishes a
framework for measuring fair value in generally accepted accounting principles
and expands disclosures about fair value measurements. SFAS No. 157
does not require any new fair value measurements but may require some entities
to change their measurement practices. In February 2008, the FASB
issued FSP FAS 157-1, “Application of FASB Statement No. 157 to FASB Statement
No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements
for Purposes of Lease Classification or Measurement under Statement 13,” which
removes certain leasing transactions from the scope of SFAS No. 157, and FSP FAS
157-2, “Effective Date of FASB Statement No. 157,” which defers the effective
date of SFAS No. 157 for one year for certain nonfinancial assets and
nonfinancial liabilities, except those that are recognized or disclosed at fair
value in the financial statements on a recurring basis. Effective
January 1, 2008, we adopted SFAS No. 157, except for measurements of those
nonfinancial assets and liabilities subject to the one-year deferral, which for
us includes impairments of goodwill, intangible assets and other long-lived
assets, and initial measurement of asset retirement obligations, asset
exchanges, business combinations and partial sales of proved
properties. Adoption did not have a significant effect on our
consolidated results of operations or financial position. The
additional disclosures regarding assets and liabilities recorded at fair value
and measured under SFAS No. 157 are presented in Note 11.
In
October 2008, the FASB issued FSP FAS 157-3, “Determining the Fair Value of a
Financial Asset When the Market for That Asset Is Not Active,” (“FSP FAS 157-3”)
which clarifies the application of SFAS No. 157 in a market that is not active
and provides an example to illustrate key considerations in determining the fair
value of a financial asset when the market for that financial asset is not
active. FSP FAS 157-3 is effective upon issuance, including prior
periods for which financial statements have not been issued, and any revisions
resulting from a change in the valuation technique or its application shall be
accounted for as a change in accounting estimate. Application of FSP
FAS 157-3 did not cause us to change our valuation techniques for assets and
liabilities measured under SFAS No. 157.
Notes
to Consolidated Financial Statements (Unaudited)
3. Income
per Common Share
Basic income per share is based on the
weighted average number of common shares outstanding, including securities
exchangeable into common shares. Diluted income per share includes
exercise of stock options and restricted shares, provided the effect is not
antidilutive.
|
|
Three
Months Ended September 30,
|
|
|
2008
|
|
|
2007
|
|
(In
millions, except per share data)
|
Basic
|
|
Diluted
|
|
|
Basic
|
|
Diluted
|
|
|
|
|
|
Net
income
|
$
|
2,064
|
|
$
|
2,064
|
|
$
|
1,021
|
|
$
|
1,021
|
|
|
|
|
|
Weighted
average common shares outstanding
|
|
707
|
|
|
707
|
|
|
680
|
|
|
680
|
|
Effect
of dilutive securities
|
|
-
|
|
|
4
|
|
|
-
|
|
|
5
|
|
Weighted
average common shares, including
|
|
|
|
|
|
|
|
|
|
|
|
|
dilutive
effect
|
|
707
|
|
|
711
|
|
|
680
|
|
|
685
|
|
|
|
|
|
Per
share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
$
|
2.92
|
|
$
|
2.90
|
|
$
|
1.50
|
|
$
|
1.49
|
|
|
Nine
Months Ended September 30,
|
|
|
2008
|
|
|
2007
|
|
(In
millions, except per share data)
|
Basic
|
|
Diluted
|
|
|
Basic
|
|
Diluted
|
|
|
|
|
|
Income
from continuing operations
|
$
|
3,569
|
|
$
|
3,569
|
|
$
|
3,280
|
|
$
|
3,280
|
|
Discontinued
operations
|
|
-
|
|
|
-
|
|
|
8
|
|
|
8
|
|
Net
income
|
$
|
3,569
|
|
$
|
3,569
|
|
$
|
3,288
|
|
$
|
3,288
|
|
|
|
|
|
Weighted
average common shares outstanding
|
|
710
|
|
|
710
|
|
|
684
|
|
|
684
|
|
Effect
of dilutive securities
|
|
-
|
|
|
4
|
|
|
-
|
|
|
5
|
|
Weighted
average common shares, including
|
|
|
|
|
|
|
|
|
|
|
|
|
dilutive
effect
|
|
710
|
|
|
714
|
|
|
684
|
|
|
689
|
|
|
|
|
|
Per
share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from continuing operations
|
$
|
5.03
|
|
$
|
5.00
|
|
$
|
4.80
|
|
$
|
4.76
|
|
Discontinued
operations
|
$
|
-
|
|
$
|
-
|
|
$
|
0.01
|
|
$
|
0.01
|
|
Net
income
|
$
|
5.03
|
|
$
|
5.00
|
|
$
|
4.81
|
|
$
|
4.77
|
The
per share calculations above exclude 5.5 million stock options for the third
quarter and the first nine months of 2008 and 3.0 million stock options for the
third quarter and the first nine months of 2007, as they were
antidilutive.
4. Acquisition
On
October 18, 2007, we completed the acquisition of all the outstanding
shares of Western Oil Sands Inc. (“Western”) for cash and securities of $5,833
million. Subsequent to the transaction, Western’s name was changed to Marathon
Oil Canada Corporation. The acquisition was accounted for under the purchase
method of accounting and, as such, our results of operations include Western’s
results from October 18, 2007. Western’s oil sands mining and bitumen
upgrading operations are reported as a separate Oil Sands Mining segment, while
its ownership interests in leases where in-situ recovery techniques are expected
to be utilized are included in the Exploration and Production
segment.
Notes
to Consolidated Financial Statements (Unaudited)
The
following shows our unaudited pro forma data as if the acquisition of Western
had been consummated at the beginning of each period presented. The
pro forma data is based on historical information and does not reflect the
actual results that would have occurred nor is it indicative of future results
of operations.
|
|
Three
Months Ended September 30, 2007
|
|
Nine
Months Ended September 30, 2007
|
|
(In
millions, except per share amounts)
|
|
|
Revenues
and other income
|
|
$
|
17,246
|
|
|
$
|
47,670
|
|
Income
from continuing operations
|
|
|
1,086
|
|
|
|
3,102
|
|
Net
income
|
|
|
1,086
|
|
|
|
3,110
|
|
Per
share data:
|
|
|
|
|
|
|
|
|
Income
from continuing operations - basic
|
|
$
|
1.52
|
|
|
$
|
4.32
|
|
Income
from continuing operations - diluted
|
|
$
|
1.51
|
|
|
$
|
4.29
|
|
Net
income - basic
|
|
$
|
1.52
|
|
|
$
|
4.33
|
|
Net
income - diluted
|
|
$
|
1.51
|
|
|
$
|
4.30
|
|
|
|
|
|
|
|
|
|
5. Segment
Information
We
have four reportable operating segments:
|
1)
|
Exploration
and Production (“E&P”) – explores for, produces and markets liquid
hydrocarbons and natural gas on a worldwide
basis;
|
|
2)
|
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
by-products;
|
|
3)
|
Refining,
Marketing and Transportation (“RM&T”) – refines, markets and
transports crude oil and petroleum products, primarily in the Midwest,
upper Great Plains, Gulf Coast and southeastern regions of the United
States; and
|
|
4)
|
Integrated
Gas (“IG”) – markets and transports products manufactured from natural
gas, such as liquefied natural gas (“LNG”) and methanol, on a worldwide
basis, and is developing other projects to link stranded natural gas
resources with key demand areas.
|
|
(In
millions)
|
|
E&P
|
|
|
OSM
|
|
|
RM&T
|
|
|
IG
|
|
|
Total
|
|
Three
Months Ended September 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer
|
$
|
3,584
|
|
$
|
532
|
|
$
|
18,139
|
|
$
|
24
|
|
$
|
22,279
|
|
Intersegment
(a)
|
|
278
|
|
|
68
|
|
|
1
|
|
|
-
|
|
|
347
|
|
Related
parties
|
|
11
|
|
|
-
|
|
|
626
|
|
|
-
|
|
|
637
|
|
Segment
revenues
|
|
3,873
|
|
|
600
|
|
|
18,766
|
|
|
24
|
|
|
23,263
|
|
Elimination
of intersegment revenues
|
|
(278)
|
|
|
(68)
|
|
|
(1)
|
|
|
-
|
|
|
(347)
|
|
Gain
on U.K. natural gas contracts
|
|
198
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
198
|
|
Total
revenues
|
$
|
3,793
|
|
$
|
532
|
|
$
|
18,765
|
|
$
|
24
|
|
$
|
23,114
|
|
Segment
income
|
$
|
939
|
|
$
|
288
|
|
$
|
771
|
|
$
|
65
|
|
$
|
2,063
|
|
Income
from equity method investments
|
|
65
|
|
|
-
|
|
|
115
|
|
|
90
|
|
|
270
|
|
Depreciation,
depletion and amortization (b)
|
|
402
|
|
|
37
|
|
|
148
|
|
|
1
|
|
|
588
|
|
Income
tax provision (b)
|
|
991
|
|
|
98
|
|
|
464
|
|
|
34
|
|
|
1,587
|
|
Capital
expenditures (c)
|
|
738
|
|
|
271
|
|
|
765
|
|
|
3
|
|
|
1,777
|
Notes
to Consolidated Financial Statements (Unaudited)
|
(In
millions)
|
|
E&P
|
|
|
OSM
|
|
|
RM&T
|
|
|
IG
|
|
|
Total
|
|
Three
Months Ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer
|
$
|
2,318
|
|
$
|
-
|
|
$
|
14,088
|
|
$
|
64
|
|
$
|
16,470
|
|
Intersegment
(a)
|
|
116
|
|
|
-
|
|
|
115
|
|
|
-
|
|
|
231
|
|
Related
parties
|
|
13
|
|
|
-
|
|
|
402
|
|
|
-
|
|
|
415
|
|
Segment
revenues
|
|
2,447
|
|
|
-
|
|
|
14,605
|
|
|
64
|
|
|
17,116
|
|
Elimination
of intersegment revenues
|
|
(116)
|
|
|
-
|
|
|
(115)
|
|
|
-
|
|
|
(231)
|
|
Loss
on U.K. natural gas contracts
|
|
(123)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(123)
|
|
Total
revenues
|
$
|
2,208
|
|
$
|
-
|
|
$
|
14,490
|
|
$
|
64
|
|
$
|
16,762
|
|
Segment
income
|
$
|
479
|
|
$
|
-
|
|
$
|
482
|
|
$
|
52
|
|
$
|
1,013
|
|
Income
from equity method investments
|
|
60
|
|
|
-
|
|
|
44
|
|
|
66
|
|
|
170
|
|
Depreciation,
depletion and amortization (b)
|
|
254
|
|
|
-
|
|
|
146
|
|
|
1
|
|
|
401
|
|
Income
tax provision(b)
|
|
544
|
|
|
-
|
|
|
262
|
|
|
8
|
|
|
814
|
|
Capital
expenditures (c)(d)
|
|
582
|
|
|
-
|
|
|
430
|
|
|
2
|
|
|
1,014
|
|
(In
millions)
|
|
E&P
|
|
|
OSM
|
|
|
RM&T
|
|
|
IG
|
|
|
Total
|
|
Nine
Months Ended September 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer
|
$
|
9,586
|
|
$
|
631
|
|
$
|
50,739
|
|
$
|
64
|
|
$
|
61,020
|
|
Intersegment
(a)
|
|
663
|
|
|
184
|
|
|
203
|
|
|
-
|
|
|
1,050
|
|
Related
parties
|
|
40
|
|
|
-
|
|
|
1,825
|
|
|
-
|
|
|
1,865
|
|
Segment
revenues
|
|
10,289
|
|
|
815
|
|
|
52,767
|
|
|
64
|
|
|
63,935
|
|
Elimination
of intersegment revenues
|
|
(663)
|
|
|
(184)
|
|
|
(203)
|
|
|
-
|
|
|
(1,050)
|
|
Loss
on U.K. natural gas contracts
|
|
(37)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(37)
|
|
Total
revenues
|
$
|
9,589
|
|
$
|
631
|
|
$
|
52,564
|
|
$
|
64
|
|
$
|
62,848
|
|
Segment
income
|
$
|
2,451
|
|
$
|
158
|
|
$
|
854
|
|
$
|
266
|
|
$
|
3,729
|
|
Income
from equity method investments
|
|
204
|
|
|
-
|
|
|
186
|
|
|
345
|
|
|
735
|
|
Depreciation,
depletion and amortization (b)
|
|
972
|
|
|
104
|
|
|
446
|
|
|
3
|
|
|
1,525
|
|
Income
tax provision (b)
|
|
2,532
|
|
|
53
|
|
|
527
|
|
|
118
|
|
|
3,230
|
|
Capital
expenditures (c)(d)
|
|
2,387
|
|
|
781
|
|
|
1,978
|
|
|
4
|
|
|
5,150
|
Notes
to Consolidated Financial Statements (Unaudited)
|
|
(In
millions)
|
|
E&P
|
|
|
OSM
|
|
|
RM&T
|
|
|
IG
|
|
|
Total
|
|
Nine
Months Ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer
|
$
|
6,041
|
|
$
|
-
|
|
$
|
39,103
|
|
$
|
188
|
|
$
|
45,332
|
|
Intersegment
(a)
|
|
372
|
|
|
-
|
|
|
199
|
|
|
-
|
|
|
571
|
|
Related
parties
|
|
24
|
|
|
-
|
|
|
1,122
|
|
|
-
|
|
|
1,146
|
|
Segment
revenues
|
|
6,437
|
|
|
-
|
|
|
40,424
|
|
|
188
|
|
|
47,049
|
|
Elimination
of intersegment revenues
|
|
(372)
|
|
|
-
|
|
|
(199)
|
|
|
-
|
|
|
(571)
|
|
Loss
on U.K. natural gas contracts
|
|
(111)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(111)
|
|
Total
revenues
|
$
|
5,954
|
|
$
|
-
|
|
$
|
40,225
|
|
$
|
188
|
|
$
|
46,367
|
|
Segment
income
|
$
|
1,264
|
|
$
|
-
|
|
$
|
2,073
|
|
$
|
83
|
|
$
|
3,420
|
|
Income
from equity method investments
|
|
165
|
|
|
-
|
|
|
116
|
|
|
113
|
|
|
394
|
|
Depreciation,
depletion and amortization (b)
|
|
733
|
|
|
-
|
|
|
436
|
|
|
5
|
|
|
1,174
|
|
Minority
interest in loss of subsidiary
|
|
-
|
|
|
-
|
|
|
-
|
|
|
3
|
|
|
3
|
|
Income
tax provision (b)
|
|
1,438
|
|
|
-
|
|
|
1,181
|
|
|
20
|
|
|
2,639
|
|
Capital
expenditures (c)(d)
|
|
1,623
|
|
|
-
|
|
|
981
|
|
|
93
|
|
|
2,697
|
|
(a)
|
Management
believes intersegment transactions were conducted under terms comparable
to those with unrelated parties.
|
|
(b)
|
Differences
between segment totals and our totals represent amounts related to
corporate administrative activities and other unallocated items and are
included in “Items not allocated to segments, net of income taxes” in
reconciliation below.
|
|
(c)
|
Differences
between segment totals and our totals represent amounts related to
corporate administrative
activities.
|
|
(d)
|
Through
April 2007, Integrated Gas segment capital expenditures include Equatorial
Guinea LNG Holdings Limited (“EGHoldings”) at 100
percent. Effective May 1, 2007, we no longer consolidate
EGHoldings and our investment in EGHoldings is accounted for under the
equity method of accounting; therefore, EGHoldings’ capital expenditures
subsequent to April 2007 are not included in our capital
expenditures.
|
|
The
following reconciles segment income to net income as reported in the
consolidated statements of income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
September
30,
|
|
September
30,
|
|
(In
millions)
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
Segment
income
|
$
|
2,063
|
|
$
|
1,013
|
|
$
|
3,729
|
|
$
|
3,420
|
|
Items
not allocated to segments, net of income taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate
and other unallocated items
|
|
(100)
|
|
|
3
|
|
|
(141)
|
|
|
(149)
|
|
Gain
(loss) on U.K. natural gas contracts
|
|
101
|
|
|
(62)
|
|
|
(19)
|
|
|
(56)
|
|
Gain
on foreign currency derivative instruments (a)
|
|
-
|
|
|
74
|
|
|
-
|
|
|
74
|
|
Loss
on early extinguishment of debt
|
|
-
|
|
|
(7)
|
|
|
-
|
|
|
(9)
|
|
Discontinued
operations(b)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
8
|
|
Net
income
|
$
|
2,064
|
|
$
|
1,021
|
|
$
|
3,569
|
|
$
|
3,288
|
|
(a)
|
Represents
unrealized gains in the third quarter 2007 on foreign currency derivative
instruments entered into to limit our exposure to the Canadian dollar
exchange rate related to the cash portion of the purchase prices for
Western Oil Sand Inc.
|
|
(b)
|
The
Russian businesses sold in June 2006 were accounted for as discontinued
operations. Adjustments to the sales price were completed in
2007 and an additional gain on the sale of $8 million ($13 million before
income taxes) was recognized. See our 2007 Form 10-K for
further information.
|
Notes
to Consolidated Financial Statements (Unaudited)
|
The
following reconciles total revenues to sales and other operating revenues
(including consumer excise taxes) as reported in the consolidated
statements of income.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
September
30,
|
|
September
30,
|
|
(In
millions)
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
Total
revenues
|
$
|
23,114
|
|
$
|
16,762
|
|
$
|
62,848
|
|
$
|
46,367
|
|
Less: Sales
to related parties
|
|
637
|
|
|
415
|
|
|
1,865
|
|
|
1,146
|
|
Sales
and other operating revenues (including
|
|
|
|
|
|
|
|
|
|
|
|
|
consumer
excise taxes)
|
$
|
22,477
|
|
$
|
16,347
|
|
$
|
60,983
|
|
$
|
45,221
|
6. Defined
Benefit Postretirement Plans
The
following summarizes the components of net periodic benefit cost:
|
|
Three
Months Ended September 30,
|
|
|
Pension
Benefits
|
|
Other
Benefits
|
|
(In
millions)
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
Service
cost
|
$
|
37
|
|
$
|
35
|
|
$
|
5
|
|
$
|
6
|
|
Interest
cost
|
|
40
|
|
|
36
|
|
|
11
|
|
|
11
|
|
Expected
return on plan assets
|
|
(42)
|
|
|
(38)
|
|
|
-
|
|
|
-
|
|
Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
–
prior service cost (credit)
|
|
3
|
|
|
3
|
|
|
(2)
|
|
|
(2)
|
|
–
actuarial loss
|
|
8
|
|
|
9
|
|
|
-
|
|
|
2
|
|
Net
periodic benefit cost
|
$
|
46
|
|
$
|
45
|
|
$
|
14
|
|
$
|
17
|
|
|
Nine
Months Ended September 30,
|
|
|
Pension
Benefits
|
|
Other
Benefits
|
|
(In
millions)
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
Service
cost
|
$
|
110
|
|
$
|
105
|
|
$
|
14
|
|
$
|
17
|
|
Interest
cost
|
|
120
|
|
|
107
|
|
|
33
|
|
|
33
|
|
Expected
return on plan assets
|
|
(126)
|
|
|
(115)
|
|
|
-
|
|
|
-
|
|
Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
–
prior service cost (credit)
|
|
10
|
|
|
10
|
|
|
(6)
|
|
|
(7)
|
|
–
actuarial loss
|
|
23
|
|
|
27
|
|
|
1
|
|
|
6
|
|
Net
periodic benefit cost
|
$
|
137
|
|
$
|
134
|
|
$
|
42
|
|
$
|
49
|
During
the first nine months of 2008, we made contributions of $37 million to our
funded international pension plans. We expect to make additional
contributions of an estimated $32 million to our funded pension plans over the
remainder of 2008, with $29 million of that made in October
2008. Contributions made from our general assets to cover current
benefit payments related to unfunded pension and other postretirement benefit
plans were $14 million and $24 million during the first nine months of
2008.
Notes
to Consolidated Financial Statements (Unaudited)
7. Income
Taxes
The
following is an analysis of the effective income tax rates for the periods
presented:
|
|
Nine
Months Ended September 30,
|
|
|
2008
|
|
|
2007
|
|
|
Statutory
U.S. income tax rate
|
35
|
%
|
|
35
|
%
|
|
Effects
of foreign operations, including foreign tax credits
|
11
|
|
|
8
|
|
|
State
and local income taxes, net of federal income tax effects
|
1
|
|
|
2
|
|
|
Other
tax effects
|
(1)
|
|
|
(1)
|
|
|
Effective
income tax rate for continuing operations
|
46
|
%
|
|
44
|
%
|
The
geographic sources of income and related tax expense contributed to the increase
in the effective income tax rate in the first nine months of 2008 when compared
to the same period in 2007. The estimated 2008 effective tax rate is
reduced by approximately 4 percent by the reversal of previously recorded
valuation allowances on Norwegian net operating losses.
We
are continuously undergoing examination of our U.S. federal income tax returns
by the Internal Revenue Service. Such audits have been completed
through the 2005 tax year. We believe adequate provision has been
made for federal income taxes and interest which may become payable for years
not yet settled. Further, we are routinely involved in U.S. state
income tax audits and foreign jurisdiction tax audits. We believe all
other audits will be resolved within the amounts paid and/or provided for these
liabilities. As of September 30, 2008, our income tax returns remain
subject to examination in the following major tax jurisdictions for the tax
years indicated.
|
|
|
|
United
States (a)
|
2001
- 2007
|
|
Canada
|
2000
- 2007
|
|
Equatorial
Guinea
|
2006
- 2007
|
|
Libya
|
2006
- 2007
|
|
United
Kingdom
|
2005
- 2007
|
|
(a)
|
Includes
federal and state jurisdictions.
|
8. Comprehensive
Income
The
following sets forth comprehensive income for the periods
indicated:
|
|
Three
Months Ended
|
Nine
Months Ended
|
|
|
September
30,
|
September
30,
|
|
(In
millions)
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
Net
income
|
$
|
2,064
|
|
$
|
1,021
|
|
$
|
3,569
|
|
$
|
3,288
|
|
Other
comprehensive income, net of taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined
benefit postretirement plans (a)
|
|
22
|
|
|
7
|
|
|
2
|
|
|
(29)
|
|
Other
|
|
(26)
|
|
|
10
|
|
|
(27)
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive
income
|
$
|
2,060
|
|
$
|
1,038
|
|
$
|
3,544
|
|
$
|
3,271
|
|
(a)
|
During
the first six months of 2008 and 2007, changes were made to the estimates
used to measure certain assumptions necessary in determining the funded
status of our postretirement benefit plans as of December 31, 2007 and
2006.
|
Notes
to Consolidated Financial Statements (Unaudited)
|
9. Inventories
Inventories
are carried at the lower of cost or market value. The cost of
inventories of crude oil, refined products and merchandise is determined
primarily under the last-in, first-out (“LIFO”) method.
|
|
September
30,
|
|
December
31,
|
|
(In
millions)
|
2008
|
|
2007
|
|
Liquid
hydrocarbons, natural gas and bitumen
|
$
|
2,303
|
|
$
|
1,203
|
|
Refined
products and merchandise
|
|
1,847
|
|
|
1,792
|
|
Supplies
and sundry items
|
|
296
|
|
|
282
|
|
Total,
at cost
|
$
|
4,446
|
|
$
|
3,277
|
10. Property,
Plant and Equipment
Exploratory
well costs capitalized greater than one year after completion of drilling were
$54 million as of September 30, 2008, a decrease of $46 million from December
31, 2007, primarily due to the transfer of the Ozona prospect exploratory wells
in progress. A well on the Ozona prospect was re-entered and
production casing was set in the second quarter of 2008. In October
2008, the development of the Ozona prospect was authorized by our board of
directors.
11. Fair
Value Measurements
As
defined in SFAS No. 157, fair value is the price that would be received to sell
an asset or paid to transfer a liability in an orderly transaction between
market participants at the measurement date. SFAS No. 157 describes
three approaches to measuring the fair value of assets and
liabilities: the market approach, the income approach and the cost
approach, each of which includes multiple valuation techniques. The
market approach uses prices and other relevant information generated by market
transactions involving identical or comparable assets or
liabilities. The income approach uses valuation techniques to measure
fair value by converting future amounts, such as cash flows or earnings, into a
single present value amount using current market expectations about those future
amounts. The cost approach is based on the amount that would
currently be required to replace the service capacity of an
asset. This is often referred to as current replacement
cost. The cost approach assumes that the fair value would not exceed
what it would cost a market participant to acquire or construct a substitute
asset of comparable utility, adjusted for obsolescence.
SFAS
No. 157 does not prescribe which valuation technique should be used when
measuring fair value and does not prioritize among the
techniques. SFAS No. 157 establishes a fair value hierarchy that
prioritizes the inputs used in applying the various valuation
techniques. Inputs broadly refer to the assumptions that market
participants use to make pricing decisions, including assumptions about
risk. Level 1 inputs are given the highest priority in the fair value
hierarchy while Level 3 inputs are given the lowest priority. The
three levels of the fair value hierarchy are as follows.
· Level
1 – Observable inputs that reflect unadjusted quoted prices for identical assets
or liabilities in active markets as of the reporting date. Active
markets are those in which transactions for the asset or liability occur in
sufficient frequency and volume to provide pricing information on an ongoing
basis.
· Level
2 – Observable market-based inputs or unobservable inputs that are corroborated
by market data. These are inputs other than quoted prices in active
markets included in Level 1, which are either directly or indirectly observable
as of the reporting date.
· Level
3 – Unobservable inputs that are not corroborated by market data and may be used
with internally developed methodologies that result in management’s best
estimate of fair value.
We
use a market or income approach for recurring fair value measurements and
endeavor to use the best information available. Accordingly,
valuation techniques that maximize the use of observable inputs are
favored. Financial assets and liabilities are classified in their
entirety based on the lowest priority level of input that is significant to the
fair value measurement. The assessment of the significance of a
particular input to the fair value measurement requires judgment and may affect
the placement of assets and liabilities within the levels of the fair value
hierarchy.
Notes
to Consolidated Financial Statements (Unaudited)
The
following table presents net financial assets (liabilities) accounted for at
fair value on a recurring basis as of September 30, 2008:
|
(In
millions)
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Total
|
|
Derivative
Instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
$
|
44
|
|
$
|
6
|
|
$
|
(495)
|
|
$
|
(445)
|
|
Interest
rate
|
|
-
|
|
|
-
|
|
|
3
|
|
|
3
|
|
Foreign
currency
|
|
-
|
|
|
(9)
|
|
|
1
|
|
|
(8)
|
|
Total
at fair value
|
$
|
44
|
|
$
|
(3)
|
|
$
|
(491)
|
|
$
|
(450)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deposits
of $11 million in broker accounts covered by master netting agreements are
netted against the value to arrive at the fair values of commodity
derivatives. Derivatives in Level 1 are exchange-traded contracts for
crude oil, natural gas, refined products and ethanol measured at fair value with
a market approach using the close-of-day settlement prices for the
market. Derivatives in Level 2 are measured at fair value with a
market approach using broker quotes or third-party pricing services, which have
been corroborated with data from active markets. Level 3 derivatives
are measured at fair value using either a market or income
approach. Generally at least one input is unobservable, such as the
use of an internally generated model or an external data source.
Commodity
derivatives in Level 3 include a $328 million liability related to two U.K.
natural gas sales contracts that are accounted for as derivative instruments and
a $131 million liability for crude oil options related to sales of Canadian
synthetic crude oil. The fair value of the U.K. natural gas contracts
is measured with an income approach by applying the difference between the
contract price and the U.K. forward natural gas strip price to the expected
sales volumes for the shorter of the remaining contract term or 18
months. These contracts originated in the early 1990s and expire in
September 2009. The contract prices are reset annually in October
based on the previous twelve-month changes in a basket of energy and other
indices. Consequently, the prices under these contracts do not track
forward natural gas prices. The crude oil options, which expire
December 2009, are measured at fair value using a Black-Scholes option pricing
model, an income approach that utilizes prices from an active market and market
volatility calculated by a third-party service.
The following is a reconciliation of
the net beginning and ending balances recorded for derivative instruments
classified as Level 3 in the fair value hierarchy for the three and nine months
ended September 30, 2008.
|
|
|
Three
Months Ended September 30, 2008
|
|
(In
millions)
|
|
|
Beginning
balance
|
$
|
(988)
|
|
Total
realized and unrealized losses:
|
|
|
|
Included
in net income
|
|
445
|
|
Purchases,
sales, issuances and settlements, net
|
|
52
|
|
Ending
balance
|
$
|
(491)
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2008
|
|
(In
millions)
|
|
|
Beginning
balance
|
$
|
(356)
|
|
Total realized and unrealized losses:
|
|
|
|
Included
in net income
|
|
(235)
|
|
Included
in other comprehensive income
|
|
1
|
|
Purchases,
sales, issuances and settlements, net
|
|
99
|
|
Ending
balance
|
$
|
(491)
|
The
change in unrealized losses included in net income related to instruments held
at September 30, 2008 was a reduction of $413 million and an increase of
$126 million for the third quarter and first nine months of 2008. Amounts
reported in net income are classified as sales and other operating revenues or
cost of revenues for commodity derivative instruments, as net interest and other
financing income for interest rate derivative instruments and as cost of
revenues for foreign currency derivatives, except those designated as hedges of
future
Notes
to Consolidated Financial Statements (Unaudited)
capital
expenditures. Amounts related to foreign currency derivatives
designated as hedges of future capital expenditures accumulate in other
comprehensive income and are amortized to depletion, depreciation and
amortization on a units-of-production basis over the life of the capital
asset.
12. Debt
At
September 30, 2008, we had $886 million of commercial paper, at a weighted
average interest rate of 5.9 percent, outstanding under our U.S. commercial
paper program which is supported by our $3.0 billion revolving credit
facility. An additional $404 million in borrowings was outstanding
under the revolving credit facility at a weighted average interest rate of 5.0
percent. Neither commercial paper nor borrowings under the revolving
credit facility were outstanding at December 31, 2007.
In
March 2008, we issued $1 billion aggregate principal amount of senior notes
bearing interest at 5.9 percent with a maturity date of March 15,
2018. Interest on the senior notes is payable semi-annually beginning
September 15, 2008.
In
February 2008, the 805 million Canadian dollar revolving term credit facility of
Marathon Oil Canada Corporation was repaid and the facility was
terminated.
13. Stock-Based
Compensation Plans
The
following table presents a summary of stock option award and restricted stock
award activity for the nine month period ended September 30, 2008:
|
|
Stock
Options
|
|
Restricted
Stock
|
|
|
Number
of Shares (a)
|
|
|
Weighted
Average Exercise Price
|
|
Awards
|
|
|
Weighted
Average Grant Date Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at December 31, 2007
|
12,214,853
|
|
|
$34.58
|
|
1,527,831
|
|
|
$39.87
|
|
Granted
(b)
|
2,555,218
|
|
|
51.77
|
|
1,402,413
|
|
|
48.27
|
|
Options
Exercised/Stock Vested
|
(479,632)
|
|
|
23.87
|
|
(603,697)
|
|
|
29.47
|
|
Canceled
|
(365,682)
|
|
|
51.68
|
|
(117,289)
|
|
|
43.15
|
|
Outstanding
at September 30, 2008
|
13,924,757
|
|
|
$37.65
|
|
2,209,258
|
|
|
$47.87
|
|
(a)
|
Of
the stock option awards outstanding as of September 30, 2008, 5,486,987,
7,938,260 and 499,510 were outstanding under the 2007 Incentive
Compensation Plan, the 2003 Incentive Compensation Plan and the 1990 Stock
Plan, including 749,282 stock options with tandem stock appreciation
rights.
|
|
(b)
|
The
weighted average grant date fair value of stock option awards granted was
$13.03 per share.
|
14. Stockholders’
Equity
Share repurchase
– As of September 30, 2008, we had acquired 66 million common shares
at a cost of $2,922 million under our $5 billion authorized share repurchase
program, including 8 million common shares acquired during the first nine months
of 2008 at a cost of $402 million.
15. Commitments
and Contingencies
We
are the subject of, or party to, a number of pending or threatened legal
actions, contingencies and commitments involving a variety of matters, including
laws and regulations relating to the environment. The ultimate
resolution of these contingencies could, individually or in the aggregate, be
material to our consolidated financial statements. However,
management believes that we will remain a viable and competitive enterprise even
though it is possible that these contingencies could be resolved
unfavorably. Certain of our commitments are discussed
below.
We, along
with some other defendants with refinery operations, recently settled a number
of lawsuits alleging methyl tertiary butyl ether (“MTBE”) contamination of water
supply wells. We were a defendant in 40 of the cases
settled. Our share of the cash portion of the settlement was paid in
October 2008 and did not significantly impact our consolidated results of
operations, financial position or cash flows. Under the settlement, the
settling
Notes
to Consolidated Financial Statements (Unaudited)
defendants,
including our company, are responsible for addressing future MTBE contamination
in certain water supply wells. We do not expect that our share of
liability for any such future obligations under the settlement to significantly
impact our consolidated results of operations, financial position or cash
flows.
Contractual commitments – At
September 30, 2008, Marathon’s contract commitments to acquire property, plant
and equipment totaled $3,966 million.
16. Supplemental
Cash Flow Information
|
|
Nine
Months Ended September 30,
|
|
(In
millions)
|
2008
|
|
2007
|
|
|
|
|
|
|
|
|
Net
cash provided from operating activities included:
|
|
|
|
|
|
|
Interest
paid (net of amounts capitalized)
|
$
|
85
|
|
$
|
66
|
|
Income
taxes paid to taxing authorities
|
|
2,458
|
|
|
2,711
|
|
|
|
|
|
|
|
|
Noncash
investing and financing activities:
|
|
|
|
|
|
|
Bond
obligation assumed for trusteed funds
|
$
|
-
|
|
$
|
1,000
|
|
|
|
|
|
|
|
|
Noncash
effect of deconsolidation of EGHoldings:
|
|
|
|
|
|
|
Decrease
in non-cash assets
|
$
|
-
|
|
$
|
1,759
|
|
Record
equity method investment
|
|
-
|
|
|
942
|
|
Decrease
in liabilities
|
|
-
|
|
|
310
|
|
Elimination
of minority interest
|
|
-
|
|
|
544
|
|
|
|
|
|
|
|
17. Accounting
Standards Not Yet Adopted
In
June 2008, the FASB issued FSP on EITF 03-6-1, “Determining Whether Instruments
Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP
EITF 03-6-1”) which provides that unvested share-based payment awards that
contain nonforfeitable rights to dividends or dividend equivalents (whether paid
or unpaid) are participating securities and, therefore, need to be included in
the earnings allocation in computing earnings per share (”EPS”) under the
two-class method. FSP EITF 03-6-1 is effective January 1, 2009 and
all prior-period EPS data (including any amounts related to interim periods,
summaries of earnings and selected financial data) will be adjusted
retrospectively to conform to its provisions. Early application of
FSP EITF 03-6-1 is not permitted. Although restricted stock awards meet this
definition of participating securities, we do not expect application of FSP EITF
03-6-1 to have a significant impact on our reported EPS.
In April
2008, the FASB issued FSP on FAS 142-3 (“FSP FAS 142-3”)
which amends the factors that should be considered in developing renewal or
extension assumptions used to determine the useful life of a recognized
intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The
intent of this FSP is to improve the consistency between the useful life of a
recognized intangible asset and the period of expected cash flows used to
measure the fair value of the asset. FSP FAS 142-3 is effective on
January 1, 2009, early adoption is prohibited. The provisions of FSP FAS
142-3 are to be applied prospectively to intangible assets acquired after the
effective date, except for the disclosure requirements which must be applied
prospectively to all intangible assets recognized as of, and subsequent to, the
effective date. Since this standard will be applied prospectively,
adoption is not expected to have a significant impact on our consolidated
results of operations, financial position or cash flows.
In
March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative
Instruments and Hedging Activities – an amendment of FASB Statement No.
133.” This statement expands the disclosure requirements for
derivative instruments to provide information regarding (i) how and why an
entity uses derivative instruments, (ii) how derivative instruments and related
hedged items are accounted for under SFAS No. 133 and its related
interpretations and (iii) how derivative instruments and related hedged items
affect an entity’s financial position, financial performance and cash
flows. To meet these objectives, the statement requires qualitative
disclosures about objectives and strategies for using derivatives, quantitative
disclosures about fair value amounts and gains and losses on derivative
instruments and disclosures about credit-risk-related contingent features in
derivative agreements. This standard is effective January 1,
2009. The statement encourages but does not require
disclosures
Notes
to Consolidated Financial Statements (Unaudited)
for
earlier periods presented for comparative purposes at initial
adoption. We will expand our disclosures in accordance with SFAS No.
161 beginning in the first quarter of 2009; however, the adoption of this
standard is not expected to have a significant impact on our consolidated
results of operations, financial position or cash flows.
In December
2007, the FASB issued SFAS No. 141 (Revised 2007), “Business Combinations”
(”SFAS No. 141 (R)”). This statement significantly changes the
accounting for business combinations. Under SFAS No.141(R), an acquiring entity
will be required to recognize all the assets acquired, liabilities assumed and
any non-controlling interest in the acquiree at their acquisition-date fair
value with limited exceptions. The statement expands the definition of a
business and is expected to be applicable to more transactions than the previous
business combinations standard. The statement also changes the accounting
treatment for changes in control, step acquisitions, transaction costs, acquired
contingent liabilities, in-process research and development, restructuring
costs, changes in deferred tax asset valuation allowances as a result of a
business combination and changes in income tax uncertainties after the
acquisition date. Accounting for changes in valuation allowances for
acquired deferred tax assets and the resolution of uncertain tax positions for
prior business combinations will impact tax expense instead of impacting
recorded goodwill. Additional disclosures are also required. SFAS No.
141(R) is effective on January 1, 2009 for all new business
combinations. We are currently evaluating the provisions of
this statement.
Also
in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in
Consolidated Financial Statements - An Amendment of ARB No. 51.” This
statement establishes new accounting and reporting standards for the
noncontrolling interest in a subsidiary and for the deconsolidation of a
subsidiary. Specifically, this statement clarifies that a
noncontrolling interest in a subsidiary (sometimes called a minority interest)
is an ownership interest in the consolidated entity that should be reported as
equity in the consolidated financial statements, but separate from the parent's
equity. It requires that the amount of consolidated net income
attributable to the noncontrolling interest be clearly identified and presented
on the face of the consolidated income statement. SFAS No. 160
clarifies that changes in a parent's ownership interest in a subsidiary that do
not result in deconsolidation are equity transactions if the parent retains its
controlling financial interest. In addition, this statement requires
that a parent recognize a gain or loss in net income when a subsidiary is
deconsolidated, based on the fair value of the noncontrolling equity investment
on the deconsolidation date. Additional disclosures are required that
clearly identify and distinguish between the interests of the parent and the
interests of the noncontrolling owners. SFAS No. 160 is effective
January 1, 2009 and early adoption is prohibited. The statement must
be applied prospectively, except for the presentation and disclosure
requirements which must be applied retrospectively for all periods presented in
consolidated financial statements. We do not have significant
noncontrolling interests in consolidated subsidiaries, and therefore, adoption
of this standard is not expected to have a significant impact on our
consolidated results of operations, financial position or cash
flows.
18. Evaluation
of Separation of Business
On
July 31, 2008, Marathon announced that the board of directors is evaluating the
separation of Marathon into two independent, publicly-traded companies, each
focused on its own set of business opportunities. One entity would
consist of the Exploration and Production, Integrated Gas and Oil Sands Mining
businesses; and the other entity would consist of the Refining, Marketing and
Transportation business.
19. Subsequent
Events
On
October 8, 2008, we completed the sale of our 50 percent ownership interest in
Pilot Travel Centers LLC (“PTC”). Sale proceeds, before closing
costs, were $625 million, with a pretax gain on the sale of approximately $125
million expected. Immediately preceding the sale, we received a $75
million redemption of our partnership interest from PTC that was accounted for
as a return of investment.
On
October 31, 2008, we closed the sale of our Norwegian outside-operated
properties and undeveloped offshore acreage for proceeds of $320 million, before
post-closing adjustments. After post-closing adjustments are
finalized, the pretax gain is expected to be between $250 and $275
million. As of September 30, 2008, operating assets and liabilities
with a net carrying value of $36 million were classified as held for sale, with
$3 million reported in Other current assets, $94 million in Other noncurrent
assets and $61 million in Deferred credits and other liabilities on the
consolidated balance sheet.
Item
2. Management’s Discussion and Analysis of Financial Condition and Results of
Operations
Marathon
Oil Corporation is engaged in worldwide exploration, production and marketing of
liquid hydrocarbons and natural gas; mining, extraction and transportation of
bitumen from oil sands deposits in Alberta, Canada, and upgrading of the bitumen
for the production and marketing of synthetic crude oil and by-products;
domestic refining, marketing and transportation of crude oil and petroleum
products, primarily in the Midwest, upper Great Plains, Gulf Coast and
southeastern regions of the United States; and worldwide marketing and
transportation of products manufactured from natural gas, such as LNG and
methanol, and development of other projects to link stranded natural gas
resources with key demand areas. Management’s Discussion and Analysis
of Financial Condition and Results of Operations should be read in conjunction
with the Consolidated Financial Statements and Selected Notes to Consolidated
Financial Statements, the Supplemental Statistics and our 2007 Annual Report on
Form 10-K.
Certain
sections of Management’s Discussion and Analysis of Financial Condition and
Results of Operations include forward-looking statements concerning trends or
events potentially affecting our business. These statements typically
contain words such as “anticipates,” “believes,” “estimates,” “expects,”
“targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar
words indicating that future outcomes are uncertain. In accordance
with “safe harbor” provisions of the Private Securities Litigation Reform Act of
1995, these statements are accompanied by cautionary language identifying
important factors, though not necessarily all such factors, which could cause
future outcomes to differ materially from those set forth in the forward-looking
statements. For additional risk factors affecting our business, see
Item 1A. Risk Factors in our 2007 Annual Report on Form 10-K.
We
hold a 60 percent interest in Equatorial Guinea LNG Holdings Limited
(“EGHoldings”). Effective May 1, 2007, we no longer consolidate
EGHoldings. Our investment is accounted for prospectively using the
equity method of accounting. Unless specifically noted, amounts
presented for the Integrated Gas segment for periods prior to May 1, 2007,
include amounts related to the minority interests.
Overview
and Outlook
Exploration
and Production (“E&P”)
Production
Net
liquid hydrocarbon and natural gas sales averaged 379 and 369 thousand barrels
of oil equivalent per day (“mboepd”) during the third quarter and first nine
months of 2008, an increase of 2 percent and 5 percent over the same periods of
2007. Sales from the Alvheim/Vilje development offshore Norway and
the Neptune development in the Gulf of Mexico more than offset declines in sales
due to the deferral of certain production in the Gulf of Mexico as a result of
hurricanes. Natural gas sales from the Alba field in Equatorial
Guinea contributed to the increased sales in the year-to-date
period.
The
Alvheim development offshore Norway commenced production in June
2008. The Vilje field, which is tied back to the Alvheim
floating production, storage and offloading vessel, began producing July 31,
2008. Commissioning of the Alvheim/Vilje project is continuing with a
total of 10 wells currently available for production, out of 12 producing wells
planned for the first phase. We have seen extended periods of
production at facility capacity of 125 mboepd (75 mboepd net to Marathon) and
expect further stabilization at these rates. We have a 65 percent
operated interest in the Alvheim fields and a 47 percent outside-operated
interest in the Vilje field.
The
Neptune development in the Gulf of Mexico commenced production of liquid
hydrocarbons and natural gas in early July 2008 and reached full oil capacity
after 15 days of operations. The field is currently producing from 6
wells. Marathon has a 30 percent outside-operated interest in the
Neptune development. The facility’s design capacity is 50 thousand
barrels per day (“mbpd”) of oil and 50 million cubic feet per day (“mmcfd”) of
natural gas.
Hurricanes
Gustav and Ike impacted Gulf of Mexico production in the latter part of the
third quarter, resulting in 9,500 net barrels of oil equivalent per day
(“boepd”) being shut-in during the quarter. The Ewing Bank
development resumed production in late October. The outside-operated
Troika and Ursa fields remain shut-in for repairs. These fields are
expected to impact fourth quarter 2008 sales by approximately 6
mboepd. We have an approximate 65 percent working interest in Ewing
Bank, a 50 percent working interest in Troika and a 4 percent overriding royalty
interest in Ursa.
We
continue to increase sales from the Williston Basin (the Bakken shale formation)
in North Dakota. We currently have 7 rigs drilling. We
expect to drill 71 company-operated wells in 2008 and will have over 100 wells
in the play by the end of 2008.
Exploration
During
the first nine months of 2008, we announced the Portia and the Dione discoveries
on Block 31 offshore Angola which were our 27th and
28th
discoveries on Blocks 31 and 32. We also participated in 3 wells in
our Angola exploration and appraisal program that have reached total depth, the
results of which will be announced upon receipt of government and partner
approval. At September 30, 2008 we were participating in one
appraisal well in Block 32. On Block 31 we are currently drilling an
exploratory well and plan to drill two additional exploratory wells the
remainder of 2008. We hold a 10 percent outside-operated interest in
Block 31 and a 30 percent outside-operated interest in Block 32.
Offshore
Angola, we have received approval to proceed with the first deepwater oil
development project in Block 31. The development is comprised of the
Plutao, Saturno, Venus and Marte (“PSVM”) fields. Key contracts are
ready to be awarded and construction work is expected to begin later this
year. A total of 48 production and injection wells are planned for
the PSVM development.
In
the third quarter of 2008, we announced a Gulf of Mexico deepwater discovery on
the Gunflint prospect located on Mississippi Canyon Block 948. We own
a 13 percent outside-operated interest in the block. We are also
currently participating in another deepwater exploration well in the Gulf of
Mexico and an appraisal well on the Stones prospect located on Walker Ridge
Block 508. We hold a 25 percent outside-operated interest in
Stones.
In
October 2008, development of the Droshky discovery, located in the Gulf of
Mexico on Green Canyon Block 244, was authorized by our board of
directors. The initial Droshky discovery well and two sidetracks were
drilled in 2007, followed in 2008 by a second delineation and sidetrack well.
The project will consist of four development wells, which will be tied back to
the nearby outside-operated Bullwinkle platform. We have secured a rig to begin
drilling in 2009, and first production is targeted for 2010. Our share of sales
is expected to peak at about 45 mbpd of liquid hydrocarbons and 43 mmcfd of
natural gas, after royalties. We hold a 100 percent working interest in
Droshky.
Also
in October 2008, development of the Ozona prospect, located in the Gulf of
Mexico on Garden Banks Block 515 was authorized. We have secured a
rig to complete the previously drilled appraisal well and tie back to the nearby
outside-operated Auger platform. First production is expected in
2011. We hold a 68 percent working interest in Ozona.
During
the second quarter of 2008 we were awarded all 15 blocks bid in the Central Gulf
of Mexico Lease Sale No. 206 conducted by the Minerals Management Service in the
first quarter of 2008. Two blocks are 100 percent Marathon, and the
remaining blocks were bid with partners, at a total cost of $121
million. Initial drilling on these leases, and those acquired at
Lease Sale No. 205 in October 2007, is planned for 2009.
In
Indonesia, we are the operator of a drilling rig consortium which has secured a
two-year contract for a deepwater exploration drilling rig. The rig
will be used for deepwater exploration activities by us and four other companies
in Indonesia. The participants have the right to extend this rig
commitment. Additionally, in October 2008, we were granted a 49
percent interest and operatorship in the Bone Bay Block offshore
Indonesia. The Bone Bay Block is 200 miles southeast of our
PasangkayuBlock, which was awarded in 2006. Current exploration plans
call for the acquisition of 2D seismic starting in 2009, followed by drilling in
2011.
We
ceased efforts to pursue exploration opportunities in Ukraine and closed our
Kiev office in the third quarter of 2008.
Divestitures
On
October 31, 2008, we closed the sale of our outside-operated interests (24
percent of Heimdal field, 47 percent of Vale field and 20 percent of Skirne
field) and associated undeveloped acreage offshore Norway for proceeds of $320
million, before post-closing adjustments. When post-closing
adjustments are finalized, the pretax gain on the sale is expected to be between
$250 and $270 million.
During
the first quarter of 2008, we transferred our interest in an exploration and
production license in Sudan to the operator, and as a result, we no longer have
any interests in Sudan.
The
above discussions include forward-looking statements with respect to the timing
and levels of future production, and anticipated future exploratory drilling
activity. Some factors that could potentially affect these
forward-looking statements include pricing, supply and demand for petroleum
products, the amount of capital available for exploration and development,
regulatory constraints, timing of commencing production from new wells, drilling
rig availability, unforeseen hazards such as weather conditions, acts of war or
terrorist acts and the governmental or military response, and other geological,
operating and economic considerations. The foregoing forward-looking
statements may be further affected by the inability to obtain or delay in
obtaining necessary government and third-party approvals and
permits. The disposition of interests could also be adversely
affected by customary closing conditions. The foregoing factors (among others)
could cause actual results to differ materially from those set forth in the
forward-looking statements.
Oil
Sands Mining (“OSM”)
Our
bitumen production, before royalties, was 28 thousand barrels per day (“mbpd”)
in the third quarter and 25 mbpd in the first nine months of
2008. Third quarter production increased 15 percent over second
quarter as a result of a greater volume of ore being mined and available to the
mine processing facility. This improvement is largely a result of
additional shovel excavation locations being opened in the mine enabling more
consistency in ore availability.
The
Athabasca Oil Sands Project (“AOSP”) Expansion 1, which includes
construction of mining and extraction facilities at the Jackpine mine, expansion
of treatment facilities at the existing Muskeg River mine, expansion of the
Scotford upgrader and development of related infrastructure, is anticipated to
begin operations in 2010 or 2011. As recently announced by the
operator, a final investment decision on Expansion 2 has been
postponed.
In
the third quarter of 2008, following achievement of project payout, the royalty
rate increased to the 25 percent of net revenue post-payout rate from the one
percent of gross revenue rate that had been in effect for most of the
year. During the first quarter of 2008, the royalty calculation
methodology for the AOSP was revised to allow for additional eligible costs to
the project such that the royalty calculation adjusted retroactively to the one
percent as of July 1, 2007.
The
above discussion includes forward-looking statements with respect to the start
of operations of AOSP Expansion 1. Factors that could be
affected the project are transportation logistics, availability of materials and
labor, unforeseen hazards such as weather conditions, delays in obtaining or
conditions imposed by necessary government and third-party approvals and other
risks customarily associated with construction projects.
Refining,
Marketing and Transportation (“RM&T”)
Our
total refinery throughputs were 8 percent lower in the third quarter and first
nine months of 2008 than in the third quarter and first nine months of
2007. Crude oil refined likewise decreased 8 percent in the same
periods. Third quarter throughput declines were primarily
weather-related, while planned maintenance activities at several of our
refineries earlier in the year also contributed to the year-to-date throughput
declines.
Our
ethanol blending program in the third quarter of 2008 increased 50 percent
compared to the same period of 2007. For the first nine months of
2008 we blended 36 percent more ethanol than in the same period of
2007. The future expansion or contraction of our ethanol blending
program will be driven by the economics of ethanol supply and government
regulations.
Third
quarter 2008 Speedway SuperAmerica LLC same store gasoline sales volume
decreased 12 percent when compared to the third quarter of 2007 while same store
merchandise sales increased by 2 percent for the same period. Our
2007 gasoline sales included the effect of a special sales
promotion.
The
expansion of our Garyville refinery is 70 percent complete with an on-schedule
startup expected in the fourth quarter 2009. We have identified minor cost
increases for additional quantities of materials required, material and labor
cost escalation and some additional costs associated with the recent hurricanes
in the Gulf Coast region. We now project the expansion will cost about $3.4
billion, excluding capitalized interest, or about 5 percent more than the
original estimate.
All the
permits have been received for the upgrading and expansion project at the
Detroit refinery. Construction started at the end of the second
quarter of 2008. Due to the current market conditions, we are
reevaluating the project construction schedule and expect to defer the project
completion. We are currently compiling the new project schedule and
cost, and expect to complete this analysis by year end 2008.
In
October 2008, we completed the sale of our 50 percent ownership interest in
PTC. Sale proceeds, before closing costs, were $625 million, with a
pretax gain on the sale of approximately $125 million
expected. Immediately preceding the sale, we received a $75
million redemption of our partnership interest from PTC that was accounted for
as a return of investment.
The
above discussion includes forward-looking statements with respect to the
Garyville and Detroit refinery expansion projects. Factors that could
affect those projects include transportation logistics, availability of
materials and labor, unforeseen hazards such as weather conditions, delays in
obtaining or conditions imposed by necessary government and third-party
approvals, and other risks customarily associated with construction
projects. These factors (among others) could cause actual results to
differ materially from those set forth in the forward-looking
statements.
Integrated
Gas (“IG”)
We
own 45 percent of Atlantic Methanol Production Company LLC (“AMPCO”) and 60
percent of Equatorial Guinea LNG Holdings Limited (“EGHoldings”), both of which
are accounted for under the equity method of accounting. AMPCO
operates a methanol plant and EGHoldings operates a liquefied natural gas
(“LNG”) production facility, both located on
Bioko
Island, Equatorial Guinea. Alba field dry natural gas, which remains
after the condensate and liquefied petroleum gas (“LPG”) are removed, is
supplied to both of these facilities under long-term, fixed price
contracts. We consider the prices under these contracts to be
comparable to the price that could be realized from transactions with unrelated
parties in this market under the same or similar circumstances, because of the
location of the natural gas and limited local demand for natural gas in
Equatorial Guinea.
The
EGHoldings LNG production facility delivered 13 cargoes during the third quarter
of 2008. Our share of LNG sales worldwide totaled 6,048 metric tonnes
per day (“mtpd”) for the third quarter of 2008 compared to 6,137 mtpd in the
third quarter of 2007 and 6,453 mtpd in the first nine months of 2008 compared
to 3,117 mtpd in the first nine months of 2007. These LNG sales
volumes include both consolidated sales volumes and our share of the sales
volumes of equity method investees. LNG sales from Alaska are
conducted through a consolidated subsidiary. LNG and methanol sales
from Equatorial Guinea are conducted through equity method
investees.
Production
at the LNG facility in Equatorial Guinea was curtailed in July while scheduled
repairs and modifications were completed on the facility to improve the overall
efficiency of the plant. The methanol plant experienced a series of
planned and unplanned maintenance events, but the facility returned to full
production in October 2008. Neither situation significantly impacted
our financial results for the quarter.
We
continue to invest in the development of new technologies to create value and
supply new energy sources. In the first nine months of 2008, we
recorded costs of approximately $59 million related to natural gas
technology research, including completing construction and beginning the
commissioning of the demonstration plant for Gas-To-FuelsTM
technology.
Management's
Discussion and Analysis of Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated
Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
are summarized by segment in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
September
30,
|
|
September
30,
|
(In
millions)
|
2008
|
|
2007
|
|
2008
|
|
2007
|
E&P
|
$
|
3,873
|
|
$
|
2,447
|
|
$
|
10,289
|
|
$
|
6,437
|
OSM
|
|
600
|
|
|
-
|
|
|
815
|
|
|
-
|
RM&T
|
|
18,766
|
|
|
14,605
|
|
|
52,767
|
|
|
40,424
|
IG
|
|
24
|
|
|
64
|
|
|
64
|
|
|
188
|
Segment
revenues
|
|
23,263
|
|
|
17,116
|
|
|
63,935
|
|
|
47,049
|
|
|
|
|
|
|
|
|
|
|
|
|
Elimination
of intersegment revenues
|
|
(347)
|
|
|
(231)
|
|
|
(1,050)
|
|
|
(571)
|
Gain
(loss) on U.K. natural gas contracts
|
|
198
|
|
|
(123)
|
|
|
(37)
|
|
|
(111)
|
Total
revenues
|
$
|
23,114
|
|
$
|
16,762
|
|
$
|
62,848
|
|
$
|
46,367
|
|
|
|
|
|
|
|
|
|
|
|
|
Items
included in both revenues and costs and
|
|
|
|
|
|
|
|
|
|
|
|
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consumer
excise taxes on petroleum products and merchandise
|
$
|
1,273
|
|
$
|
1,352
|
|
$
|
3,784
|
|
$
|
3,856
|
E&P segment revenues
increased $1,426 million in the third quarter and $3,852 million in the first
nine months of 2008 from the comparable prior-year periods. Increased
liquid hydrocarbon realizations, averaging $111.33 per barrel in the third
quarter and $104.33 in the first nine months of 2008, account for the majority
of the revenue increase in both periods. Additionally, sales from our
new Alvheim/Vilje development in Norway increased international liquid
hydrocarbon sales volumes in the third quarter. Partially offsetting
the increase in liquid hydrocarbon realizations were lower natural gas sales
volumes in third quarter due to more natural gas storage in Ireland and
Alaska. Liquid hydrocarbon and natural gas sales volumes in the
U.S. were lower in both periods primarily due to shutdowns in the third quarter
for hurricanes and natural production declines in the Gulf of
Mexico. Sales from the new Neptune development in the Gulf of Mexico
reversed the decline trend in the third quarter, keeping liquid hydrocarbon
sales volumes flat in spite of the hurricanes. For the nine-month period,
international natural gas sales volumes continue to reflect an increase related
to sales to the EGHoldings LNG production facility that began operations in the
second quarter of 2007. This increase in fixed-price sales volumes
limited the increase in our average international natural gas
realizations. Our share of the income
ultimately generated by the subsequent export of LNG produced by EGHoldings, as
well as methanol produced by AMPCO, is reflected in our Integrated Gas segment
as discussed below.
See
Supplemental Statistics for information regarding net sales volumes and average
realizations by geographic area.
Excluded
from E&P segment revenues were gains of $198 million and losses of $123
million for the third quarters of 2008 and 2007 related to natural gas sales
contracts in the U.K. that are accounted for as derivative
instruments. For the first nine months of 2008 and 2007 losses of $37
million and $111 million are excluded from E&P segment
revenues.
OSM segment revenues totaled $600 million
in the third quarter and $815 million in the first nine months of
2008. Revenues in both periods include the impact of derivative
instruments intended to mitigate price risk related to future sales of synthetic
crude. Pretax gains of $255 million were included in the third
quarter and pretax losses of $131 million in the first nine months of
2008. Net synthetic crude sales for the third quarter of 2008 were 32
mbpd at an average realized price of $113.42 per barrel.
See
Item 3. Quantitative and Qualitative Disclosures About Market Risk for
additional discussion about derivative instruments.
RM&T segment revenues
increased $4,161 million in the third quarter of 2008 and $12,343 million in the
first nine months of 2008 from the comparable prior-year periods. The third
quarter increase primarily reflects increased refined product selling prices,
slightly offset by lower refined product and liquid hydrocarbon sales volumes.
For the nine -month period the increase primarily reflects increased refined
product and liquid hydrocarbon selling prices, slightly offset by lower refined
product and liquid hydrocarbon sales volumes.
For
information on segment income, see Segment Results.
Income from equity method
investments increased $100 million in the third quarter of 2008 and $341
million in the first nine months of 2008 from the comparable prior-year
periods. Income from the EGHoldings LNG production facility accounts
for most of the increase, as it began operations in May
2007. Forty-two cargoes of LNG were delivered during the first nine
months of 2008, an average of 14 per quarter, as compared to an average of 5 per
quarter in the first nine months of 2007.
Cost of revenues increased
$4,041 million and $15,074 million in the third quarter and first nine months of
2008 from the comparable prior-year periods. These increases resulted
primarily from increases in acquisition costs of crude oil, refinery charge and
blend stocks and purchased refined products in the RM&T
segment.
Exploration expenses were $109
million and $368 million in the third quarter and first nine months of 2008,
including expenses related to dry wells of $24 million and $106
million. Exploration expenses were $88 million and $264 million
in the third quarter and first nine months of 2007, including expenses related
to dry wells of $22 million and $76 million. Other exploration
expense increases in the first nine months of 2008 relate to the acquisition of
seismic data in Indonesia and the evaluation of Canadian in-situ oil sands
leases.
Gain on foreign currency derivative
instruments in the third quarter of 2007 primarily represents unrealized
gains on foreign currency derivative instruments entered to limit our exposure
to changes in the Canadian dollar exchange rate related to the cash portion of
the purchase price for Western.
Provision for income taxes
increased $911 million and $437 million in the third quarter and first nine
months of 2008 from the comparable periods of 2007 as a result of increases in
income before income taxes. The geographic sources of income and
related tax expense contributed to the increase in the effective income tax
rates for the first nine months of 2008 when compared to the same period in
2007. The estimated 2008 effective tax rate was reduced by less
than 4 percentage points by the reversal of previously recorded valuation
allowances on Norwegian net operating losses.
The
following is an analysis of the effective income tax rates for the first nine
months of 2008 and 2007:
|
Nine
Months Ended September 30,
|
|
2008
|
|
|
2007
|
|
Statutory
U.S. income tax rate
|
35
|
%
|
|
35
|
%
|
Effects
of foreign operations, including foreign tax credits
|
11
|
|
|
8
|
|
State
and local income taxes, net of federal income tax effects
|
1
|
|
|
2
|
|
Other
tax effects
|
(1)
|
|
|
(1)
|
|
Effective
income tax rate for continuing operations
|
46
|
%
|
|
44
|
%
|
Discontinued
operations in 2007 is
a sales price adjustment on the June 2006 sale of our Russian oil exploration
and production businesses.
Segment
Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
income is summarized in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
September
30,
|
|
September
30,
|
(In
millions)
|
2008
|
|
|
2007
|
|
2008
|
2007
|
E&P
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
285
|
|
$
|
147
|
|
$
|
888
|
|
$
|
470
|
International
|
|
654
|
|
|
332
|
|
|
1,563
|
|
|
794
|
E&P
segment
|
|
939
|
|
|
479
|
|
|
2,451
|
|
|
1,264
|
|
|
|
|
|
|
|
|
|
|
|
|
OSM
|
|
288
|
|
|
-
|
|
|
158
|
|
|
-
|
RM&T
|
|
771
|
|
|
482
|
|
|
854
|
|
|
2,073
|
IG
|
|
65
|
|
|
52
|
|
|
266
|
|
|
83
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
income
|
|
2,063
|
|
|
1,013
|
|
|
3,729
|
|
|
3,420
|
Items
not allocated to segments, net of income taxes:
|
|
|
|
|
|
|
|
|
|
|
|
Corporate
and other unallocated items
|
|
(100)
|
|
|
3
|
|
|
(141)
|
|
|
(149)
|
Gain
(loss) on U.K. natural gas contracts
|
|
101
|
|
|
(62)
|
|
|
(19)
|
|
|
(56)
|
Gain
on foreign currency derivative instruments
|
|
-
|
|
|
74
|
|
|
-
|
|
|
74
|
Loss
on early extinguishment of debt
|
|
-
|
|
|
(7)
|
|
|
-
|
|
|
(9)
|
Discontinued
operations
|
|
-
|
|
|
-
|
|
|
-
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
$
|
2,064
|
|
$
|
1,021
|
|
$
|
3,569
|
|
$
|
3,288
|
United States E&P income
increased $138 million, or 94 percent, and $418 million, or 89 percent, in the
third quarter and first nine months of 2008 compared to the same periods of
2007. Pretax income increased $214 million and $665 million in the
same periods. The higher pretax income in both periods is primarily a
result of higher liquid hydrocarbon and natural gas realizations, partially
offset by increased production taxes and higher depletion, depreciation and
amortization, primarily related to new production.
International E&P income
increased $322 million, or 97 percent, and $769 million, or 97 percent, in the
third quarter and first nine months of 2008 compared to the same periods of
2007. Pretax income increased $693 million and $1,616 million in the same
periods. The higher pretax income in both periods is primarily a
result of higher liquid hydrocarbon sales volumes and realizations, partially
offset by increased costs related to new production.
OSM segment income was $288
million and $ 158 million in the third quarter and first nine months of
2008. The third quarter reflects a $190 million after-tax gain,
which includes a realized after-tax loss of $24 million and an unrealized
after-tax gain of $214 million, on derivative instruments intended to mitigate
price risk related to future sales of synthetic crude oil. For the
first nine months of 2008, the after-tax derivative loss was $98 million, of
which $39 million is unrealized.
RM&T segment income
increased by $289 million, or 60 percent, and decreased $1,219 million, or 59
percent, in the third quarter and first nine months of 2008 compared to the same
periods of 2007. Pretax income increased $491 million and decreased
$1,873 million in the same periods. The changes in RM&T pretax income in
both periods are primarily the result of changes in the refining and wholesale
marketing gross margin. Our refining and wholesale marketing gross margin
averaged 25.19 cents per gallon in the third quarter of 2008 and 11.37 cents per
gallon in the first nine months of 2008 compared to 17.17 cents per gallon and
23.17 cents per gallon in the comparable periods of 2007. The major cause of the
margin increase in the third quarter was the significant drop in crude oil
prices during the quarter and an increase in the average sweet/sour
differentials compared to the same quarter last year. For the
nine-month period, the major cause of the margin decline was the significant
increase in crude oil prices in the first half of 2008, which was not reflected
fully in our selling prices.
Our
refining and wholesale marketing gross margin also included pretax derivative
gains of $156 million and losses of $151 million in the third quarter and first
nine months of 2008 compared to losses of $360 million and $472 million in the
third quarter and first nine months of 2007. For a more complete explanation of
our strategies to manage market risk related to commodity prices, see
Quantitative and Qualitative Disclosures About Market Risk.
IG segment
income increased $13 million in the third quarter of 2008 and $183
million in the first nine months of 2008 compared to the same periods of 2007
due primarily to increased income from our equity method investment in
EGHoldings. The first LNG deliveries from EGHoldings’ LNG production
facility were made in the second quarter of 2007.
Management’s
Discussion and Analysis of Cash Flows and Liquidity
Cash
Flows
Net cash provided by operating
activities totaled $4,807 million in the first nine months of 2008,
compared to $2,951 million in the first nine months of 2007. Cash
provided by operating activities benefited from increased E&P segment income
and the addition of the OSM segment, partially offset by a lower refining and
wholesale marketing gross margin in the RM&T segment for the nine months of
2008.
Net cash used in investing activities
totaled $4,800 million in the first nine months of 2008, compared to
$2,609 million in the first nine months of 2007. Capital expenditures
were $5,168 million compared with $2,725 million for the comparable prior-year
period, with the increased spending related the Garyville refinery expansion,
the Alvheim development, Gulf of Mexico exploration and development projects and
the AOSP. See Supplemental Statistics for information regarding
capital expenditures by segment. We received $402 million and $163
million of the funds held in trust related to the Garyville expansion in
the first nine months of 2008 and 2007.
Net cash provided by financing
activities was $302 million in the first nine months of 2008, compared to
$333 million in the first nine months of 2007. Significant uses of cash in
financing activities during both periods included stock repurchases, repayments
of maturing debt and dividend payments. Financing activities for the
first nine months of 2008 included the issuance of $1.0 billion in senior notes,
$886 million of net commercial paper borrowings, $404 million in borrowings
under the revolving credit facility and the payment and termination of the
Marathon Oil Canada Corporation (previously Western Oil Sands Inc.) revolving
credit facility. Financing activities for the first nine months of
2007 included the issuance of $1.5 billion in senior notes and borrowings of
$578 million from the Norwegian export credit agency.
Dividends
to Stockholders
On
October 29, 2008, our Board of Directors declared a dividend of 24 cents per
share, payable December 10, 2008, to stockholders of record at the close of
business on November 19, 2008.
Derivative
Instruments
See
Item 3. Quantitative and Qualitative Disclosures About Market Risk for a
discussion of derivative instruments and associated market risk.
Liquidity
and Capital Resources
Our
main sources of liquidity are cash and cash equivalents, internally generated
cash flow from operations and a $3.0 billion committed revolving credit
facility. Because of the alternatives available to us, we believe
that our liquidity is adequate.
Subsequent
to September 30, 2008, our liquidity has been further enhanced by the sales of
our ownership interest in PTC and of our non-core Norwegian
assets. At October 31, 2008, our cash plus availability under our
revolving credit facility totaled approximately $5 billion.
We
expect our 2009 capital investment and exploration budget, which we intend to
finalize and announce in January 2009, to be more than 15 percent lower than
2008 expenditures, which were budgeted at $8 billion.
We
believe that our access to capital resources is adequate to fund operations,
including our capital spending programs, dividends, repayment of debt maturities
and any amounts that ultimately may be paid in connection with
contingencies.
Recently,
many financial institutions (including insurance companies and banks) have come
under significant financial stress, and in some cases, have become
insolvent. Financial institutions participate in our revolving credit
facility; provide us with business insurance coverage, cash management services,
commercial letters of credit and short-term investments; and are counterparties
to our commodity and foreign exchange derivative instruments. We have
not
experienced a significant adverse impact on our
business to date. Turmoil in the capital markets could significantly
increase our costs associated with borrowing.
Credit
Arrangements
Our
senior unsecured debt is currently rated investment grade by Standard and Poor’s
Corporation, Moody’s Investor Services, Inc. and Fitch Ratings with ratings of
BBB+, Baa1, and BBB+. Following our announcement regarding the
possible separation of the upstream and downstream businesses, Moody's Investors
Service placed our ratings under review for a possible downgrade. Fitch
Ratings affirmed our current ratings and maintained their
previously announced negative outlook. Standard & Poor's
Ratings Services placed our ratings on credit watch with negative
implications. Standard & Poor’s removed the negative credit watch on
our short-term borrowings in August 2008 when we publicly confirmed our
intention to issue commercial paper in the normal course of business with all
issued paper maturing and settling prior to any potential separation
date.
At
September 30, 2008, we had $404 million of borrowings against our revolving
credit facility and we had commercial paper outstanding in the amount of $886
million under our U.S. commercial paper program that is backed by the revolving
credit facility. Effective April 3, 2008, Marathon entered into an
amendment to its revolving credit facility, extending the termination date on
$2,625 million from May 2012 to May 2013. The remaining $375 million
continues to have a termination date of May 2012. No single lender in
our committed revolving credit facility holds more than 10 percent of the
facility.
On
March 12, 2008, we issued $1 billion aggregate principal amount of senior notes
bearing interest at 5.9 percent with a maturity date of March 15,
2018. Interest on the senior notes is payable semi-annually beginning
September 15, 2008.
On
July 26, 2007, we filed a universal shelf registration statement with the
Securities and Exchange Commission, under which we, as a well-known seasoned
issuer, have the ability to issue and sell an indeterminate amount of various
types of debt and equity securities.
Our
cash-adjusted debt-to-capital ratio (total debt-minus-cash to total
debt-plus-equity-minus-cash) was 23 percent at September 30, 2008, compared to
22 percent at year-end 2007 as shown below. This includes $485
million of debt that is serviced by United States Steel Corporation (“United
States Steel”).
|
|
September
30,
|
|
|
December
31,
|
(In
millions)
|
|
2008
|
|
|
2007
|
Short-term
debt
|
$
|
1,290
|
|
$
|
-
|
Long-term
debt due within one year
|
|
88
|
|
|
1,131
|
Long-term
debt
|
|
7,074
|
|
|
6,084
|
|
|
|
|
|
|
Total
debt
|
$
|
8,452
|
|
$
|
7,215
|
|
|
|
|
|
|
Cash
|
$
|
1,479
|
|
$
|
1,199
|
Trusteed
funds from revenue bonds
|
$
|
363
|
|
$
|
744
|
Equity
|
$
|
21,927
|
|
$
|
19,223
|
|
|
|
|
|
|
Calculation:
|
|
|
|
|
|
|
|
|
|
|
|
Total
debt
|
$
|
8,452
|
|
$
|
7,215
|
Minus
cash
|
|
1,479
|
|
|
1,199
|
Minus
trusteed funds from revenue bonds
|
|
363
|
|
|
744
|
|
|
|
|
|
|
Total
debt minus cash
|
$
|
6,610
|
|
$
|
5,272
|
|
|
|
|
|
|
Total
debt
|
|
8,452
|
|
|
7,215
|
Plus
equity
|
|
21,927
|
|
|
19,223
|
Minus
cash
|
|
1,479
|
|
|
1,199
|
Minus
trusteed funds from revenue bonds
|
|
363
|
|
|
744
|
|
|
|
|
|
|
Total
debt plus equity minus cash
|
$
|
28,537
|
|
$
|
24,495
|
|
|
|
|
|
|
Cash-adjusted
debt-to-capital ratio
|
|
23%
|
|
|
22%
|
|
|
|
|
|
|
Our
opinions concerning liquidity and our ability to avail ourselves in the future
of the financing options mentioned in the above forward-looking statements are
based on currently available information. If this information proves to be
inaccurate, future availability of financing may be adversely affected.
Estimates may differ from actual results. Factors that affect the
availability of financing include our performance (as measured by various
factors including cash provided from operating activities), the state of
worldwide debt and equity markets, investor perceptions and expectations of past
and future performance, the global financial climate, and, in particular, with
respect to borrowings, the levels of our outstanding debt and credit ratings by
rating agencies.
Stock
Repurchase Program
Since
January 2006, our Board of Directors has authorized a common share repurchase
program totaling $5 billion. As of September 30, 2008, we had
repurchased 66 million common shares at a cost of $2,922
million. Purchases under the program may be in either open market
transactions, including block purchases, or in privately negotiated
transactions. This program may be changed based upon our financial
condition or changes in market conditions and is subject to termination prior to
completion. The program’s authorization does not include specific
price targets or timetables. The timing of purchases under the
program will be influenced by cash generated from operations, proceeds from
potential asset sales, cash from available borrowings and market
conditions.
The
forward-looking statements about our common stock repurchase program are based
on current expectations, estimates and projections and are not guarantees of
future performance. Actual results may differ materially from these
expectations, estimates and projections and are subject to certain risks,
uncertainties and other factors, some of which are beyond our control and are
difficult to predict. Some factors that could cause actual results to
differ materially are changes in prices of and demand for crude oil, natural gas
and refined products, actions of competitors, disruptions or interruptions of
our production, refining and mining operations due to unforeseen hazards such as
weather conditions, acts of war or terrorist acts and the governmental or
military response thereto, and other operating and economic
considerations.
Contractual
Cash Obligations
As
of September 30, 2008, our consolidated contractual cash obligations have
decreased by $3,134 million from December 31, 2007. Our purchase
obligations under crude oil, refinery feedstock, refined product and ethanol
contracts, which are primarily short term, decreased $4,071 million primarily
related to decreased crude oil volumes, partially offset by higher liquefied
petroleum gas volumes when comparing the first nine months of 2008 to December
31, 2007. Short and long-term debt increased by $1,257 million
primarily due to the issuance of commercial paper and borrowings under our
revolving credit facility. There have been no other significant
changes to our obligations to make future payments under existing contracts
subsequent to December 31, 2007. The portion of our obligations to
make future payments under existing contracts that have been assumed by United
States Steel has not changed significantly subsequent to December 31,
2007.
Evaluation
of Separation of Business
On
July 31, 2008, Marathon announced that the board of directors is evaluating the
separation of Marathon into two independent, publicly-traded companies, each
focused on its own set of business opportunities. One entity would
consist of the Exploration and Production, Integrated Gas and Oil Sands Mining
businesses; and the other entity would consist of the Refining, Marketing and
Transportation business. Results of this evaluation and a decision by
the board of directors are anticipated in the fourth quarter of
2008.
The
above discussion includes forward-looking statements with respect to the
evaluation of separating Marathon into two distinct businesses. Some
factors that could potentially affect these forward-looking statements include
board approval, future financial condition and operating results, and economic,
business, competitive and/or regulatory factors affecting our
business. The foregoing factors (among others) could cause actual
results to differ materially from those set forth in the forward-looking
statements.
Critical
Accounting Estimates
The
preparation of financial statements in accordance with generally accepted
accounting principles requires us to make estimates and assumptions that affect
the reported amounts of assets and liabilities and the disclosure of contingent
assets and liabilities as of the date of the consolidated financial statements
and the reported amounts of revenues and expenses during the respective
reporting periods. Actual results could differ from the estimates and
assumptions used.
Certain
accounting estimates are considered to be critical if (1) the nature of the
estimates and assumptions is material due to the levels of subjectivity and
judgment necessary to account for highly uncertain matters or the susceptibility
of such matters to change; and (2) the impact of the estimates and assumptions
on financial condition or operating performance is material.
There
have been no changes to our critical accounting estimates subsequent to December
31, 2007, except those related to fair value estimates resulting from the
adoption of SFAS No. 157 as discussed below.
Fair
Value Estimates
On
January 1, 2008, we adopted SFAS No. 157 for those financial assets and
liabilities recognized or disclosed at fair value in the consolidated financial
statements on a recurring basis. SFAS No. 157 defines fair value,
establishes a framework for measuring fair value and expands disclosures about
fair value measurements. It does not require us to make any new fair
value measurements, but rather establishes a fair value hierarchy that
prioritizes the inputs to the valuation techniques used to measure fair
value. Level 1 inputs are given the highest priority in the fair
value hierarchy, as they represent observable inputs that reflect unadjusted
quoted prices for identical assets or liabilities in active markets as of the
reporting date, while Level 3 inputs are given the lowest priority, as they
represent unobservable inputs that are not corroborated by market
data. Valuation techniques that maximize the use of observable inputs
are favored.
FSP
FAS 157-2, “Effective Date of FASB Statement No. 157,” deferred the effective
date of SFAS No. 157 for one year for certain nonfinancial assets and
nonfinancial liabilities, which for us includes impairments of goodwill,
intangible assets and other long-lived assets, and initial measurement of asset
retirement obligations, asset exchanges, business combinations and partial sales
of proved properties.
For
Marathon, the primary impact from the adoption of SFAS No. 157 at January 1,
2008, related to the fair value measurement of derivative
instruments. Additional information about derivatives and their
valuation may be found in Item 3. Quantitative and Qualitative Disclosures About
Market Risk.
Environmental
Matters
We
have incurred and will continue to incur substantial 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, production processes and whether it is
also engaged in the petrochemical business or the marine transportation of crude
oil, refined products and feedstocks.
Legislation
and regulations pertaining to climate change and greenhouse gas emissions have
the potential to impact us. The Energy Independence and Security Act
and California laws contain provisions related to greenhouse gas
emissions. Other climate change legislation and regulations both in
the United States and abroad are in various stages of
development. Our industry, and other businesses throughout the United
States, is also awaiting the U.S. Environmental Protection Agency’s (“EPA”)
actions upon the remand of the U.S. Supreme Court decision in Massachusetts v.
USEPA, which could have impacts on a number of air emissions permitting and
environmental regulatory programs. In July of 2008, the EPA issued an
Advanced Notice of Proposed Rulemaking (“ANPR”) to address the Supreme Court
decision and to seek public input through November 2008 on potential actions it
may take to regulate greenhouse gas emissions. Action by EPA on the
ANPR is not expected until 2009. Emissions arise from our operations,
including the refining of crude oil and the transportation of crude oil and
refined products. Although there may be adverse financial impact
(including compliance costs, potential permitting delays and potential reduced
demand for certain refined products) associated with any legislation,
regulation, EPA or other action, the extent and magnitude of that impact cannot
be reliably or accurately estimated due to the fact that requirements have only
recently been adopted and the present uncertainty regarding the additional
measures and how they will be implemented. Litigation has also been
brought against emitters of greenhouse gas emissions but Marathon has not been
named in those cases. As part of our commitment to environmental
stewardship, we estimate and publicly report greenhouse gas emissions from our
operations. We are working to continuously improve the accuracy and
completeness of these estimates. In addition, we continuously strive
to improve operational and energy efficiencies through resource and energy
conservation where practicable and cost effective.
The
EPA is in the process of implementing regulations to address current National
Ambient Air Quality Standards (“NAAQS”) for fine particulate emissions and
ozone. In connection with these standards, the EPA will designate
certain areas as “nonattainment,” meaning that the air quality in such areas
does not meet the NAAQS. To address these nonattainment areas, the
EPA proposed a rule in 2004 called the Interstate Air Quality Rule (“IAQR”) that
would require significant emissions reductions in numerous
states. The final rule, promulgated in 2005, was renamed the Clean
Air Interstate Rule (“CAIR”). While the EPA expected that states
would meet their CAIR obligations by requiring emissions reductions from
electric generating units, states were to have the final say on what sources
they regulate to meet attainment criteria. Significant uncertainty in
the final requirements of this rule comes from litigation (State of North
Carolina, et al v. EPA). On July 11, 2008, the U.S. Court of Appeals
for the District of Columbia Circuit vacated the CAIR in its entirety and
remanded it to EPA to promulgate a rule consistent with the Court’s
opinion. The CAIR will be significantly altered, and it could result
in changes in emissions control strategies. Our refinery operations
are located in affected states and some of these states may choose to propose
more stringent fuels requirements to meet the
CAIR. Also,
in 2007, the EPA proposed a revised ozone standard. This revised
ozone standard was promulgated in March of 2008, and the EPA is starting the
multi-year process to develop the implementing rules required by the Clean Air
Act. We cannot reasonably estimate the final financial impact of the
state actions to implement the CAIR until the EPA has issued a revised rule and
states have taken further action to implement that rule. We also
cannot reasonably estimate the final financial impact of the revised ozone
standard until the implementing rules are established and judicial challenges
over the revised ozone standard are resolved.
We
previously reported that we have not finalized our strategy or cost estimate to
comply with Mobile Source Air Toxics II regulations relating to benzene, but the
cost estimate may be approximately $1 billion over a three-year period beginning
in 2008, with $31 million spent through September 30, 2008. This cost
estimate is a forward-looking statement and is subject to change as further work
is completed in 2008 and 2009.
There
have been no other significant changes to our environmental matters subsequent
to December 31, 2007.
Other
Contingencies
We are the subject of, or a party to, a
number of pending or threatened legal actions, contingencies and commitments
involving a variety of matters, including laws and regulations relating to the
environment. The ultimate resolution of these contingencies could, individually
or in the aggregate, be material to us. However, we believe that we will remain
a viable and competitive enterprise even though it is possible that these
contingencies could be resolved unfavorably to us. See Management’s Discussion
and Analysis of Financial Condition and Results of Operations – Liquidity and
Capital Resources.
Accounting
Standards Not Yet Adopted
In
June 2008, the FASB issued FSP on EITF 03-6-1, “Determining Whether Instruments
Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP
EITF 03-6-1”) which provides that unvested share-based payment awards that
contain nonforfeitable rights to dividends or dividend equivalents (whether paid
or unpaid) are participating securities and, therefore, need to be included in
the earnings allocation in computing earnings per share (”EPS”) under the
two-class method. FSP EITF 03-6-1 is effective January 1, 2009 and
all prior-period EPS data (including any amounts related to interim periods,
summaries of earnings and selected financial data) will be adjusted
retrospectively to conform to its provisions. Early application of
FSP EITF 03-6-1 is not permitted. Although restricted stock awards meet this
definition of participating securities, we do not expect application of FSP EITF
03-6-1 to have a significant impact on our reported EPS.
In
April 2008, the FASB issued FSP on FAS 142-3 (“FSP FAS 142-3”)
which amends the factors that should be considered in developing renewal or
extension assumptions used to determine the useful life of a recognized
intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The
intent of this FSP is to improve the consistency between the useful life of a
recognized intangible asset and the period of expected cash flows used to
measure the fair value of the asset. FSP FAS 142-3 is effective on
January 1, 2009, early adoption is prohibited. The provisions of FSP FAS
142-3 are to be applied prospectively to intangible assets acquired after the
effective date, except for the disclosure requirements which must be applied
prospectively to all intangible assets recognized as of, and subsequent to, the
effective date. Since this standard will be applied prospectively,
adoption is not expected to have a significant impact on our consolidated
results of operations, financial position or cash flows.
In
March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative
Instruments and Hedging Activities – an amendment of FASB Statement No.
133.” This statement expands the disclosure requirements for
derivative instruments to provide information regarding (i) how and why an
entity uses derivative instruments, (ii) how derivative instruments and related
hedged items are accounted for under SFAS No. 133 and its related
interpretations and (iii) how derivative instruments and related hedged items
affect an entity’s financial position, financial performance and cash
flows. To meet these objectives, the statement requires qualitative
disclosures about objectives and strategies for using derivatives, quantitative
disclosures about fair value amounts and gains and losses on derivative
instruments and disclosures about credit-risk-related contingent features in
derivative agreements. This standard is effective January 1,
2009. The statement encourages but does not require disclosures for
earlier periods presented for comparative purposes at initial
adoption. We will expand our disclosures in accordance with SFAS No.
161 beginning in the first quarter of 2009; however, the adoption of this
standard is not expected to have a significant impact on our consolidated
results of operations, financial position or cash flows.
In
December 2007, the FASB issued SFAS No. 141 (Revised 2007), “Business
Combinations” (”SFAS No. 141 (R)”). This statement
significantly changes the accounting for business combinations. Under SFAS
No.141(R), an acquiring entity will be required to recognize all the assets
acquired, liabilities assumed and any non-controlling interest in the acquiree
at their acquisition-date fair value with limited exceptions. The statement
expands the definition of a business and is expected to be applicable to more
transactions than the previous business combinations standard. The statement
also changes the accounting treatment for changes in control, step acquisitions,
transaction costs, acquired contingent
liabilities,
in-process research and development, restructuring costs, changes in deferred
tax asset valuation allowances as a result of a business combination and changes
in income tax uncertainties after the acquisition date. Accounting
for changes in valuation allowances for acquired deferred tax assets and the
resolution of uncertain tax positions for prior business combinations will
impact tax expense instead of impacting recorded goodwill. Additional
disclosures are also required. SFAS No. 141(R) is effective on January 1, 2009
for all new business combinations. We are currently evaluating
the provisions of this statement.
Also
in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in
Consolidated Financial Statements - An Amendment of ARB No. 51.” This
statement establishes new accounting and reporting standards for the
noncontrolling interest in a subsidiary and for the deconsolidation of a
subsidiary. Specifically, this statement clarifies that a
noncontrolling interest in a subsidiary (sometimes called a minority interest)
is an ownership interest in the consolidated entity that should be reported as
equity in the consolidated financial statements, but separate from the parent's
equity. It requires that the amount of consolidated net income
attributable to the noncontrolling interest be clearly identified and presented
on the face of the consolidated income statement. SFAS No. 160
clarifies that changes in a parent's ownership interest in a subsidiary that do
not result in deconsolidation are equity transactions if the parent retains its
controlling financial interest. In addition, this statement requires
that a parent recognize a gain or loss in net income when a subsidiary is
deconsolidated, based on the fair value of the noncontrolling equity investment
on the deconsolidation date. Additional disclosures are required that
clearly identify and distinguish between the interests of the parent and the
interests of the noncontrolling owners. SFAS No. 160 is effective
January 1, 2009 and early adoption is prohibited. The statement must
be applied prospectively, except for the presentation and disclosure
requirements which must be applied retrospectively for all periods presented in
consolidated financial statements. We do not have significant
noncontrolling interests in consolidated subsidiaries, and therefore, adoption
of this standard is not expected to have a significant impact on our
consolidated results of operations, financial position or cash
flows.
ITEM
3. Quantitative and Qualitative Disclosures About Market Risk
We
are exposed to market risks related to the volatility of crude oil, natural gas
and refined product prices. We employ various strategies, including
the use of commodity derivative instruments, to manage the risks related to
these price fluctuations. We are also exposed to market risks related
to changes in interest rates and foreign currency exchange rates. We
employ various strategies, including the use of financial derivative
instruments, to manage the risks related to these fluctuations. We
are at risk for changes in the fair value of all of our derivative instruments;
however, such risk should be mitigated by price or rate changes related to the
underlying commodity or financial transaction.
We
believe that our use of derivative instruments, along with our risk assessment
procedures and internal controls, does not expose us to material adverse
consequences. While the use of derivative instruments could
materially affect our results of operations in particular quarterly or annual
periods, we believe that the use of these instruments will not have a material
adverse effect on our financial position or liquidity.
Commodity
Price Risk
Our
strategy is to obtain competitive prices for our products and allow operating
results to reflect market price movements dictated by supply and
demand. We use a variety of commodity derivative instruments,
including futures, forwards, swaps and combinations of options, as part of an
overall program to manage commodity price risk in our different
businesses. We also may utilize the market knowledge gained from
these activities to do a limited amount of trading not directly related to our
physical transactions.
Our
E&P segment primarily uses commodity derivative instruments to mitigate the
natural gas price risk during the time that the natural gas is held in storage
before it is sold or on natural gas that is purchased to be marketed with our
own natural gas production. We also may use commodity derivative
instruments selectively to protect against price decreases on portions of our
future sales of liquid hydrocarbons or natural gas when it is deemed
advantageous to do so. The majority of these derivatives are measured at fair
value with a market approach using broker quotes or third-party pricing
services, which have been corroborated with data from active markets, making
them a Level 2 in the fair value hierarchy described by SFAS No.
157.
Unrealized
gains and losses on certain natural gas contracts in the United Kingdom that are
accounted for as derivative instruments are excluded from E&P segment
income. These contracts originated in the early 1990s and expire in
September 2009. The contract prices are reset annually in October
based on the previous twelve-month changes in a basket of energy and other
indices. Consequently, the prices under these contracts do not track
forward natural gas prices. The reported fair value of the U.K. natural gas
contracts is measured with an income approach by applying the difference between
the contract price and the U.K. forward natural gas strip price to the expected
sales volumes for the shorter of the remaining contract term or 18
months. Such an internally generated model is classified as Level 3
in the fair value hierarchy described by SFAS No. 157.
Our
OSM segment may use commodity derivative instruments to protect against price
decreases on portions of our future sales of synthetic crude oil when it is
deemed advantageous to do so. The reported fair value of these
crude oil options, which expire December 2009, is measured using a Black-Scholes
option pricing model, which is an income approach that utilizes prices from the
active commodity market and market volatility calculated by a third-party
service. Because a third-party service is used, and their inputs
represent unobservable market data, these are classified as Level 3 in the fair
value hierarchy.
Our
RM&T segment primarily uses commodity derivative instruments on a selective
basis to mitigate crude oil price risk during the time that crude oil
inventories are held before they are actually refined into salable petroleum
products. We also use derivative instruments in our RM&T segment
to manage price risk related to refined petroleum products, feedstocks used in
the refining process and ethanol blended with refined petroleum
products. We use commodity derivative instruments to mitigate crude
oil price risk between the time that crude oil purchases are priced and when
they are actually refined into salable petroleum products, but we have decreased
our use of derivatives in this manner as described further below. The
majority of these derivatives are exchange-traded contracts for crude oil,
natural gas, refined products and ethanol measured at fair value with a market
approach using the close-of-day settlement prices for the market making them a
Level 1 in the fair value hierarchy. When broker accounts are covered
by master netting agreements the broker deposits are netted against the value to
arrive at the fair values of Level 1 and Level 2 commodity
derivatives.
Generally,
commodity derivative instruments used in our E&P segment qualify for hedge
accounting. As a result, we do not recognize in net income any
changes in the fair value of those derivative instruments until the underlying
physical transaction occurs. We have not qualified commodity
derivative instruments used in our OSM or RM&T segments for hedge
accounting. As a result, we recognize in net income all changes in
the fair value of derivative instruments used in those operations.
Open
Commodity Derivative Positions as of September 30, 2008 and Sensitivity
Analysis
At
September 30, 2008, our E&P segment held open derivative contracts to
mitigate the price risk on natural gas held in storage or purchased to be
marketed with our own natural gas production in amounts that were in line with
normal levels of activity. At September 30, 2008, we had no open
derivative contracts related to our future sales of liquid hydrocarbons and
natural gas and therefore remained substantially exposed to market prices of
these commodities.
Our
OSM segment holds options indexed to West Texas Intermediate crude oil, covering
a three-year period ending December 31, 2009. The premiums for the
put options were partially offset by the sale of call options for the same
period, resulting in a net premium liability. Payment of the net
premium liability is deferred until the settlement of the option
contracts. We have entered no new derivatives since we acquired
the OSM business.
At
September 30, 2008, the number of open derivative contracts held by our RM&T
segment was lower than in previous periods. Starting in the second
quarter of 2008, we decreased our use of derivatives to mitigate crude oil price
risk between the time that domestic spot crude oil purchases are priced and when
they are actually refined into salable petroleum products. Instead,
we are addressing this price risk through other means, including changes in
contractual terms and crude oil acquisition practices.
Additionally,
in previous periods, certain contracts in our RM&T segment for the purchase
or sale of commodities were not qualified or designated as normal purchase or
normal sales under generally accepted accounting principles and therefore were
accounted for as derivative instruments. During the second quarter of
2008, as we decreased our use of derivatives, we began to designate such
contracts for the normal purchase and normal sale exclusion as we entered into
new arrangements. We intend to continue to designate new contracts as
normal purchase or normal sales contracts.
Sensitivity
analysis of the incremental effects on income from operations (“IFO”) of
hypothetical 10 percent and 25 percent changes in commodity prices for open
commodity derivative instruments as of September 30, 2008, is provided in the
following table. The direction of the price change used in
calculating the sensitivity amount for each commodity reflects that which would
result in the largest incremental decrease in IFO when applied to the commodity
derivative instruments used to hedge that commodity.
|
Incremental
Decrease in IFO Assuming a Hypothetical Price Change of (a)
|
|
(In
millions)
|
|
10%
|
|
|
25%
|
Commodity
Derivative Instruments: (b)
|
|
|
|
|
|
Crude
oil
|
$
|
98
|
(c) |
$
|
250 (c)
|
Natural
gas
|
|
73
|
(c) |
|
157 (c)
|
Refined
products
|
|
13
|
(d) |
|
32 (d)
|
(a)
|
We
remain at risk for possible changes in the market value of commodity
derivative instruments; however, such risk should be mitigated by price
changes in the underlying physical commodity. Effects of these
offsets are not reflected in the sensitivity analysis. Amounts
reflect hypothetical 10 percent and 25 percent changes in closing commodity prices for each open contract
position at September 30, 2008. Included in the natural gas
impacts above are $73 million and $158 million for hypothetical price
changes of 10 percent and 25 percent related to the U.K. natural gas
contracts accounted for as derivative instruments. We evaluate
our portfolio of commodity derivative instruments on an ongoing basis and
add or revise strategies in anticipation of changes in market conditions
and in risk profiles. We are also exposed to credit risk in the
event of nonperformance by counterparties. The creditworthiness
of counterparties is reviewed continuously and master netting agreements
are used when practical. Changes to the portfolio after
September 30, 2008, would cause future IFO effects to differ from those
presented above.
|
(b)
|
The
number of net open contracts for the E&P segment varied throughout the
third quarter of 2008, from a low of 21 contracts on July 1, 2008, to a
high of 381 contracts on July 27, 2008, and averaged 211 for the
quarter. The number of net open contracts for the RM&T
segment varied throughout the third quarter of 2008, from a low of 151
contracts on September 11, 2008, to a high of 7,475 contracts on August
13, 2008, and averaged 3,662 for the quarter. The number of net
open contracts for the OSM segment varied throughout the third quarter of
2008, from a low of 15,995 contracts on September 30, 2008 to a high of
18,130 contracts on July 1, 2008 and averaged 17,068 for the
quarter. The commodity derivative instruments used and
positions taken will vary and, because of these variations in the
composition of the portfolio over time, the number of open contracts by
itself cannot be used to predict future income
effects.
|
Interest
Rate Risk
We
are impacted by interest rate fluctuations which affect the fair value of
certain financial instruments. We manage our exposure to interest
rate movements by utilizing financial derivative instruments. The
primary objective of
this
program is to reduce our overall cost of borrowing by managing the mix of fixed
and floating interest rate debt in our portfolio. As of September 30,
2008, we had multiple interest rate swap agreements with a total notional amount
of $450 million, designated as a fair value hedge, which effectively resulted in
an exchange of existing obligations to pay fixed interest rates for obligations
to pay floating rates. The weighted average floating rate on these
swap agreements is LIBOR plus 2.060 percent.
Sensitivity
analysis of the projected incremental effect of a hypothetical 10 percent change
in interest rates on financial assets and liabilities as of September 30, 2008,
is provided in the following table.
|
|
|
Incremental
Change in Fair Value
|
(In
millions)
|
Fair
Value
|
|
Financial
assets (liabilities): (a)
|
|
|
|
|
|
|
|
|
|
Receivable
from United States Steel
|
|
$
|
469
|
|
|
|
$
|
13
|
(c) |
Interest
rate swap agreements
|
|
$
|
5
|
(b) |
|
|
$
|
5
|
(c) |
Long-term
debt, including amounts due within one year
|
|
$
|
(6,263)
|
(b) |
|
|
$
|
(366)
|
(c) |
(a)
|
Fair
values of cash and cash equivalents, receivables, notes payable, 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)
|
For
receivables from United States Steel and long-term debt, this assumes a 10
percent decrease in the weighted average yield-to-maturity of our
receivables and long-term debt at September 30, 2008. For
interest rate swap agreements, this assumes a 10 percent decrease in the
effective swap rate at September 30,
2008.
|
At
September 30, 2008, our portfolio of long-term debt was substantially comprised
of fixed rate instruments. Therefore, the fair value of the portfolio
is relatively sensitive to interest rate fluctuations. Our
sensitivity to interest rate declines and corresponding increases in the fair
value of our debt portfolio unfavorably affects our results of operations and
cash flows only when we elect to repurchase or otherwise retire fixed-rate debt
at prices above carrying value.
Foreign
Currency Exchange Rate Risk
We
manage our exposure to foreign currency exchange rates by utilizing forward and
option contracts. The primary objective of this program is to reduce
our exposure to movements in foreign currency exchange rates by locking in such
rates. The following tables summarize our derivative foreign currency
derivative instruments as of September 30, 2008.
(In
millions)
|
Period
|
|
|
Notional
Amount
|
Average
Forward Rate (a)
|
|
Fair Value
(b)
|
Foreign
Currency Forwards:
|
|
|
|
|
|
|
|
Dollar
(Canada)
|
November
2008 - February 2010
|
|
$
|
375
|
1.036 (d)
|
$
|
(10)
|
Euro
|
November
2008 - January 2009
|
|
$
|
25
|
1.413 (d)
|
$
|
-
|
Kroner
(Norway)
|
October
2008 - October 2009
|
|
$
|
36
|
6.085 (c)
|
$
|
1
|
(a)
|
Rates
shown are weighted average forward rates for the
period.
|
(b)
|
Fair
value was based on market rates.
|
(c)
|
U.S.
dollar to foreign currency.
|
(d)
|
Foreign
currency to U.S. dollar.
|
(In
millions)
|
Period
|
|
Notional
Amount
|
Weighted
Average Exercise Price (a)
|
|
Fair
Value (b)
|
Foreign
Currency Options:
|
|
|
|
|
|
|
Dollar
(Canada)
|
October
2008 - December 2008
|
|
100
|
1.015 (c)
|
|
1
|
(a)
|
Rates
shown are weighted average exercise prices for the
period.
|
(b)
|
Fair
value was based on market rates.
|
(c)
|
U.S.
dollar to foreign currency.
|
The aggregate
cash flow effect on foreign currency contracts of a hypothetical 10 percent
change to exchange rates at September
30, 2008, would be approximately $39 million.
Safe
Harbor
These
quantitative and qualitative disclosures about market risk include
forward-looking statements with respect to management’s opinion about risks
associated with the use of derivative instruments. These statements
are based on certain assumptions with respect to market prices and industry
supply of and demand for crude oil, natural gas, refined products and other
feedstocks. If these assumptions prove to be inaccurate, future
outcomes with respect to our use of derivative instruments may differ materially
from those discussed in the forward-looking statements.
Item
4. Controls and Procedures
An
evaluation of the effectiveness of the design and operation of our disclosure
controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the
Securities Exchange Act of 1934) 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. During the quarter ended
September 30, 2008, there
were no changes in our internal control over financial reporting that have
materially affected, or were reasonably likely to materially affect, our
internal control over financial reporting.
We
review and modify our financial and operational controls on an ongoing basis to
ensure that those controls are adequate to address changes in our business as it
evolves. We believe that our existing financial and operational
controls and procedures are adequate.
MARATHON
OIL CORPORATION
Supplemental
Statistics (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
September
30,
|
|
September
30,
|
(In millions, except as
noted)
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
Income
|
|
|
|
|
|
|
|
|
|
|
Exploration
and Production
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
285
|
|
$
|
147
|
|
$
|
888
|
|
$
|
470
|
International
|
|
654
|
|
|
332
|
|
|
1,563
|
|
|
794
|
E&P
segment
|
|
939
|
|
|
479
|
|
|
2,451
|
|
|
1,264
|
Oil
Sands Mining
|
|
288
|
|
|
-
|
|
|
158
|
|
|
-
|
Refining,
Marketing and Transportation
|
|
771
|
|
|
482
|
|
|
854
|
|
|
2,073
|
Integrated
Gas
|
|
65
|
|
|
52
|
|
|
266
|
|
|
83
|
Segment
income
|
|
2,063
|
|
|
1,013
|
|
|
3,729
|
|
|
3,420
|
Items
not allocated to segments, net of income taxes:
|
|
|
|
|
|
|
|
|
|
|
|
Corporate
and other unallocated items
|
|
(100)
|
|
|
3
|
|
|
(141)
|
|
|
(149)
|
Gain
(loss) on U.K. natural gas contracts
|
|
101
|
|
|
(62)
|
|
|
(19)
|
|
|
(56)
|
Gain
on foreign currency derivative instruments
|
|
-
|
|
|
74
|
|
|
-
|
|
|
74
|
Loss
on early extinguishment of debt
|
|
-
|
|
|
(7)
|
|
|
-
|
|
|
(9)
|
Discontinued
operations
|
|
-
|
|
|
-
|
|
|
-
|
|
|
8
|
Net
income
|
$
|
2,064
|
|
$
|
1,021
|
|
$
|
3,569
|
|
$
|
3,288
|
Capital
Expenditures
|
|
|
|
|
|
|
|
|
|
|
|
Exploration
and Production
|
$
|
738
|
|
$
|
582
|
|
$
|
2,387
|
|
$
|
1,623
|
Oil
Sands Mining
|
|
271
|
|
|
-
|
|
|
781
|
|
|
-
|
Refining,
Marketing and Transportation
|
|
765
|
|
|
430
|
|
|
1,978
|
|
|
981
|
Integrated
Gas (a)
|
|
3
|
|
|
2
|
|
|
4
|
|
|
93
|
Corporate
|
|
9
|
|
|
12
|
|
|
18
|
|
|
28
|
Total
|
$
|
1,786
|
|
$
|
1,026
|
|
$
|
5,168
|
|
$
|
2,725
|
Exploration
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
68
|
|
$
|
53
|
|
$
|
173
|
|
$
|
137
|
International
|
|
41
|
|
|
35
|
|
|
195
|
|
|
127
|
Total
|
$
|
109
|
|
$
|
88
|
|
$
|
368
|
|
$
|
264
|
E&P
Operating Statistics
|
|
|
|
|
|
|
|
|
|
|
|
Net
Liquid Hydrocarbon Sales (mbpd) (b)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
63
|
|
|
63
|
|
|
63
|
|
|
66
|
|
|
|
|
|
|
|
|
|
|
|
|
Europe
|
|
66
|
|
|
33
|
|
|
43
|
|
|
33
|
Africa
|
|
95
|
|
|
103
|
|
|
93
|
|
|
100
|
Total
International
|
|
161
|
|
|
136
|
|
|
136
|
|
|
133
|
Worldwide
|
|
224
|
|
|
199
|
|
|
199
|
|
|
199
|
Net
Natural Gas Sales (mmcfd) (b)(c)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
426
|
|
|
464
|
|
|
446
|
|
|
478
|
|
|
|
|
|
|
|
|
|
|
|
|
Europe
|
|
156
|
|
|
195
|
|
|
195
|
|
|
206
|
Africa
|
|
346
|
|
|
372
|
|
|
379
|
|
|
221
|
Total
International
|
|
502
|
|
|
567
|
|
|
574
|
|
|
427
|
Worldwide
|
|
928
|
|
|
1,031
|
|
|
1,020
|
|
|
905
|
Total
Worldwide Sales (mboepd)
|
|
379
|
|
|
371
|
|
|
369
|
|
|
350
|
(a)
|
Through
April 2007, includes EGHoldings at 100 percent. Effective May
1, 2007, we no longer consolidate EGHoldings and its investment in
EGHoldings is accounted for prospectively using the equity method of
accounting; therefore, EGHoldings’ capital expenditures subsequent to
April 2007 are not included in our capital
expenditures.
|
(b)
|
Amounts
reflect sales after royalties, except for Ireland where amounts are before
royalties.
|
(c)
|
Includes
natural gas acquired for injection and subsequent resale of 2 mmcfd and 51
mmcfd in the third quarters of 2008 and 2007, and 21 mmcfd and 49 mmcfd
for the first nine months of 2008 and
2007.
|
Supplemental
Statistics (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
September
30,
|
|
|
September
30,
|
(In millions, except as
noted)
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
E&P
Operating Statistics (continued)
|
|
|
|
|
|
|
|
|
|
|
|
Average
Realizations (d)
|
|
|
|
|
|
|
|
|
|
|
|
Liquid
Hydrocarbons (per bbl)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
106.81
|
|
$
|
63.53
|
|
$
|
100.27
|
|
$
|
55.83
|
|
|
|
|
|
|
|
|
|
|
|
|
Europe
|
|
118.52
|
|
|
73.19
|
|
|
115.15
|
|
|
63.80
|
Africa
|
|
109.36
|
|
|
69.48
|
|
|
102.11
|
|
|
60.57
|
Total
International
|
|
113.10
|
|
|
70.37
|
|
|
106.21
|
|
|
61.37
|
Worldwide
|
$
|
111.33
|
|
$
|
68.21
|
|
$
|
104.33
|
|
$
|
59.54
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
Gas (per mcf)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
7.70
|
|
$
|
5.14
|
|
$
|
7.70
|
|
$
|
5.74
|
|
|
|
|
|
|
|
|
|
|
|
|
Europe
|
|
8.85
|
|
|
6.47
|
|
|
8.10
|
|
|
5.95
|
Africa(e)
|
|
0.25
|
|
|
0.25
|
|
|
0.25
|
|
|
0.25
|
Total
International
|
|
2.92
|
|
|
2.38
|
|
|
2.91
|
|
|
3.01
|
Worldwide
|
$
|
5.11
|
|
$
|
3.63
|
|
$
|
5.00
|
|
$
|
4.45
|
|
|
|
|
|
|
|
|
|
|
|
|
OSM
Operating Statistics
|
|
|
|
|
|
|
|
|
|
|
|
Net
Bitumen Production (mbpd) (f)
|
|
28
|
|
|
-
|
|
|
25
|
|
|
-
|
Net
Synthetic Crude Sales (mbpd) (f)
|
|
32
|
|
|
-
|
|
|
31
|
|
|
-
|
Synthetic
Crude Average Realization (per bbl)
|
$
|
113.42
|
|
$
|
-
|
|
$
|
106.37
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
RM&T
Operating Statistics
|
|
|
|
|
|
|
|
|
|
|
|
Refinery
Runs (mbpd)
|
|
|
|
|
|
|
|
|
|
|
|
Crude
oil refined
|
|
955
|
|
|
1,042
|
|
|
941
|
|
|
1,028
|
Other
charge and blend stocks
|
|
189
|
|
|
199
|
|
|
201
|
|
|
211
|
Total
|
|
1,144
|
|
|
1,241
|
|
|
1,142
|
|
|
1,239
|
Refined
Product Yields (mbpd)
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
586
|
|
|
646
|
|
|
598
|
|
|
649
|
Distillates
|
|
358
|
|
|
358
|
|
|
336
|
|
|
352
|
Propane
|
|
21
|
|
|
24
|
|
|
22
|
|
|
24
|
Feedstocks
and special products
|
|
95
|
|
|
111
|
|
|
104
|
|
|
118
|
Heavy
fuel oil
|
|
20
|
|
|
27
|
|
|
24
|
|
|
25
|
Asphalt
|
|
79
|
|
|
93
|
|
|
75
|
|
|
87
|
Total
|
|
1,159
|
|
|
1,259
|
|
|
1,159
|
|
|
1,255
|
|
|
|
|
|
|
|
|
|
|
|
|
Refined
Products Sales Volumes (mbpd) (g)
|
|
1,357
|
|
|
1,440
|
|
|
1,335
|
|
|
1,403
|
Refining
and Wholesale Marketing Gross
|
|
|
|
|
|
|
|
|
|
|
|
Margin
(per gallon) (h)
|
$
|
0.2519
|
|
$
|
0.1717
|
|
$
|
0.1137
|
|
$
|
0.2317
|
Speedway
SuperAmerica
|
|
|
|
|
|
|
|
|
|
|
|
Retail
outlets
|
|
1,620
|
|
|
1,637
|
|
|
-
|
|
|
-
|
Gasoline
and distillate sales (millions of gallons)
|
|
796
|
|
|
892
|
|
|
2,376
|
|
|
2,520
|
Gasoline
and distillate gross margin (per gallon)
|
$
|
0.1690
|
|
$
|
0.1103
|
|
$
|
0.1235
|
|
$
|
0.1115
|
Merchandise
sales
|
$
|
764
|
|
$
|
752
|
|
$
|
2,133
|
|
$
|
2,110
|
Merchandise
gross margin
|
$
|
197
|
|
$
|
191
|
|
$
|
541
|
|
$
|
533
|
|
|
|
|
|
|
|
|
|
|
|
|
IG
Operating Statistics
|
|
|
|
|
|
|
|
|
|
|
|
Net
Sales (mtpd) (i)
|
|
|
|
|
|
|
|
|
|
|
|
LNG
|
|
6,048
|
|
|
6,137
|
|
|
6,453
|
|
|
3,117
|
Methanol
|
|
757
|
|
|
1,421
|
|
|
1,024
|
|
|
1,285
|
(d)
|
Excludes
gains and losses on traditional derivative instruments and the unrealized
effects U.K. natural gas contracts that are accounted for as
derivatives.
|
(e)
|
Primarily
represents a fixed price under long-term contracts with Alba Plant LLC,
AMPCO and EGHoldings, equity method investees. We include our
share of Alba Plant LLC’s income in our E&P segment and we include our
share of AMPCO’s and EGHoldings’ income in our Integrated Gas
segment.
|
(f)
|
Amounts
are before royalties.
|
(g)
|
Total
average daily volumes of all refined product sales to wholesale, branded
and retail (SSA) customers.
|
(h)
|
Sales
revenue less cost of refinery inputs, purchased products and manufacturing
expenses, including depreciation.
|
(i)
|
Includes
both consolidated sales volumes and our share of the sales volumes of
equity method investees. LNG sales from Alaska are conducted
through a consolidated subsidiary. LNG and methanol sales from
Equatorial Guinea are conducted through equity method
investees.
|
Part
II – OTHER INFORMATION
Item
1. Legal Proceedings
MTBE
Litigation
We,
along with some other defendants with refinery operations, recently settled a
number of lawsuits alleging methyl tertiary butyl ether (“MTBE”) contamination
of water supply wells. We were a defendant in 40 of the cases
settled. Our share of the cash portion of the settlement was paid in
October 2008 and did not significantly impact our consolidated results of
operations, financial position or cash flows. Under the settlement, the settling
defendants, including our company, are responsible for addressing future MTBE
contamination in certain water supply wells. We do not expect that
our share of liability for any such future obligations under the settlement to
significantly impact our consolidated results of operations, financial position
or cash flows.
We,
along with other companies with refinery operations, remain a defendant in 21
cases arising in three states alleging damages for MTBE
contamination. Like the cases that were recently settled, the
remaining cases, have been consolidated in a multi-district litigation (“MDL”)
in the Southern District of New York for pretrial proceedings. Twenty
of the remaining cases allege damages to water supply wells, similar to the
damages claimed in the settled cases. In the other remaining case, the State of
New Jersey is seeking natural resources damages allegedly resulting from
contamination of groundwater by MTBE. This is the only MTBE contamination case
in which natural resources damages are sought. We do not expect that our share
of liability, if any, for the remaining cases to significantly impact our
consolidated results of operations, financial position or cash
flows.
Product
Contamination Litigation
A lawsuit was filed in the United
States District Court for the Southern District of West Virginia which alleges
that the Catlettsburg, Kentucky, refinery distributed contaminated gasoline to
wholesalers and retailers for a period prior to August, 2003, causing permanent
damage to storage tanks, dispensers and related equipment, resulting in lost
profits, business disruption and personal and real property
damages. Following the incident, we conducted remediation
operations at affected facilities, and we have denied that any permanent damages
resulted from the incident. Class action certification was granted in August
2007. We have entered into a tentative settlement agreement in this case, but
both a notice to the class members and approval by the court after a fairness
hearing are required before the settlement can be
finalized. The settlement is not expected to significantly
impact our consolidated results of operations, financial position or cash
flows.
Environmental
Proceedings
The
U.S. Occupational Safety and Health Administration (“OSHA”) announced a National
Emphasis Program pursuant to which it plans to inspect domestic petroleum
refinery locations. The inspections began in 2007 and have focused on
compliance with the OSHA Process Safety Management requirements. An
inspection was conducted by U.S. OSHA in late 2007 at the Canton, Ohio refinery.
That inspection resulted in an informal settlement agreement with OSHA in
December 2007 under which we paid a penalty of $321,500 and agreed to various
abatement measures. U.S. OSHA also conducted a one-week inspection of
our Robinson, Illinois, refinery in the first quarter of 2008. An inspection of
the Detroit, Michigan, refinery was conducted in the fall of 2008 as a prelude
to an inspection of the refinery for OSHA VPP status. U.S. OSHA and
Kentucky OSHA have conducted extensive inspections of our Texas City, Texas, and
Catlettsburg, Kentucky, refineries, respectively, in the summer and fall of
2008. No enforcement has been taken with regard to the 2008 Robinson and Detroit
inspections and one citation with no penalty was assessed at
Catlettsburg. Enforcement is expected in the fourth quarter of 2008
related to the Texas City inspection and the outcome is not expected to be
significant. U.S. OSHA or state OSHAs may conduct inspections of our other
refineries during 2008 or 2009 and enforcement actions may result from these
inspections.
Item
1A. Risk Factors
We
are subject to various risks and uncertainties in the course of our
business. See the discussion of such risks and uncertainties under
Item 1A. Risk Factors in our 2007 Annual Report on Form 10-K. There
have been no material changes from the risk factors previously disclosed in that
Form 10-K.
Item 2. Unregistered Sales of
Equity Securities and Use of Proceeds
|
|
|
|
|
|
|
(a)
|
(b)
|
(c)
|
(d)
|
|
|
|
Total
Number of Shares Purchased as Part of Publicly Announced Plans or Programs
(d)
|
Approximate
Dollar Value of Shares that May Yet Be Purchased Under the Plans or
Programs (d)
|
|
|
|
|
|
|
|
Total
Number of
|
Average
Price Paid
|
Period
|
Shares
Purchased (a)(b)
|
per
Share
|
|
|
|
|
|
07/01/08
– 07/31/08
|
1,107,468
|
$46.67
|
1,092,100
|
$2,131,137,229
|
08/01/08
– 08/31/08
|
1,064,237
|
$45.23
|
1,062,700
|
$2,083,081,024
|
09/01/08
– 09/30/08
|
210,395 (c)
|
$44.94
|
171,000
|
$2,080,366,711
|
Total
|
2,382,100
|
$45.87
|
2,325,800
|
|
(a)
|
18,831
shares of restricted stock were delivered by employees to Marathon, upon
vesting, to satisfy tax withholding
requirements.
|
(b)
|
Under
the terms of the transaction whereby we acquired the minority interest in
Marathon Petroleum Company and other businesses from Ashland, Marathon
paid Ashland shareholders cash in lieu of issuing fractional shares of our
common stock to which such holders would otherwise be
entitled. We acquired 18 shares due to acquisition share
exchanges and Ashland share transfers pending at the closing of the
transaction.
|
(c)
|
37,451
shares were repurchased in open-market transactions to satisfy the
requirements for dividend reinvestment under the Marathon Oil Corporation
Dividend Reinvestment and Direct Stock Purchase Plan (the “Dividend
Reinvestment Plan”) by the administrator of the Dividend Reinvestment
Plan. Shares needed to meet the requirements of the Dividend Reinvestment
Plan are either purchased in the open market or issued directly by
Marathon.
|
(d)
|
We
announced a share repurchase program in January 2006, and amended it
several times in 2007 for a total authorized program of $5
billion. As of September 30, 2008, 66 million split-adjusted
common shares had been acquired at a cost of $2,922 million, which
includes transaction fees and commissions that are not reported in the
table above.
|
Item
6. Exhibits
3.1
|
By-laws
of Marathon Oil Corporation, effective October 29, 2008 (incorporated by
reference to Exhibit 3.1 of the Form 8-K filed November 4,
2008)
|
10.1
|
Marathon
Oil Corporation 1990 Stock Plan, as Amended and Restated Effective January
1, 2002
|
10.2
|
First
Amendment to Marathon Oil Corporation 1990 Stock Plan (as Amended and
Restated Effective January 1, 2002)
|
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
|
SIGNATURES
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized.
November
7, 2008
|
MARATHON
OIL CORPORATION
|
|
|
|
By:
Michael K. Stewart
|
|
Michael
K. Stewart
|
|
Vice
President, Accounting and
Controller
|