Delaware
|
73-0785597
|
|
(State
or other jurisdiction of incorporation
or
organization)
|
(I.R.S.
employer identification number)
|
|
100
Glenborough Drive, Suite 100
|
||
Houston,
Texas
|
77067
|
|
(Address
of principal executive offices)
|
(Zip
Code)
|
|
(281)
872-3100
(Registrant’s
telephone number, including area
code)
|
Large
accelerated filer [X]
|
Accelerated
filer [ ]
|
Non-accelerated
filer [ ]
|
Smaller
reporting company [ ]
|
(Do
not check if a smaller reporting
company)
|
|
||
Page
|
||
Item
1.
|
Financial Statements
|
|
3
|
||
4
|
||
5
|
||
6
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||
7
|
||
Item 2.
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26
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Item 3.
|
43
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Item 4.
|
44
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Item 1.
|
44
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|
Item 1A.
|
44
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|
Item 2.
|
45
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Item 3.
|
45
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Item
4.
|
46
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Item 5.
|
46
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Item 6.
|
46
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Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Revenues
|
||||||||||||||||
Oil,
Gas and NGL Sales
|
$ | 573 | $ | 1,040 | $ | 1,440 | $ | 3,115 | ||||||||
Income
from Equity Method Investees
|
25 | 40 | 52 | 158 | ||||||||||||
Other
Revenues
|
23 | 18 | 61 | 55 | ||||||||||||
Total
Revenues
|
621 | 1,098 | 1,553 | 3,328 | ||||||||||||
Costs
and Expenses
|
||||||||||||||||
Lease
Operating Expense
|
88 | 98 | 281 | 268 | ||||||||||||
Production
and Ad Valorem Taxes
|
25 | 47 | 66 | 141 | ||||||||||||
Transportation
Expense
|
18 | 14 | 43 | 43 | ||||||||||||
Exploration
Expense
|
27 | 39 | 102 | 181 | ||||||||||||
Depreciation,
Depletion and Amortization
|
205 | 194 | 601 | 593 | ||||||||||||
General
and Administrative
|
53 | 63 | 173 | 184 | ||||||||||||
Asset
Impairments
|
- | 38 | 437 | 38 | ||||||||||||
Other
Operating (Income) Expense, Net
|
34 | 60 | 22 | 107 | ||||||||||||
Total
Operating Expenses
|
450 | 553 | 1,725 | 1,555 | ||||||||||||
Operating
Income (Loss)
|
171 | 545 | (172 | ) | 1,773 | |||||||||||
Other
(Income) Expense
|
||||||||||||||||
(Gain)
Loss on Commodity Derivative Instruments
|
28 | (875 | ) | 95 | 190 | |||||||||||
Interest,
Net of Amount Capitalized
|
23 | 18 | 64 | 52 | ||||||||||||
Other
Non-Operating (Income) Expense, Net
|
5 | (52 | ) | 18 | (42 | ) | ||||||||||
Total
Non-Operating (Income) Expense
|
56 | (909 | ) | 177 | 200 | |||||||||||
Income
(Loss) Before Income Taxes
|
115 | 1,454 | (349 | ) | 1,573 | |||||||||||
Income
Tax Provision (Benefit)
|
8 | 480 | (210 | ) | 528 | |||||||||||
Net
Income (Loss)
|
$ | 107 | $ | 974 | $ | (139 | ) | $ | 1,045 | |||||||
Earnings
(Loss) Per Share, Basic
|
$ | 0.62 | $ | 5.64 | $ | (0.80 | ) | $ | 6.06 | |||||||
Earnings
(Loss) Per Share, Diluted
|
0.61 | 5.37 | (0.80 | ) | 5.86 | |||||||||||
Weighted
Average Number of Shares Outstanding, Basic
|
173 | 173 | 173 | 172 | ||||||||||||
Weighted
Average Number of Shares Outstanding, Diluted
|
175 | 176 | 173 | 176 | ||||||||||||
The
accompanying notes are an integral part of these financial
statements.
|
||||||||||||||||
(unaudited)
September 30,
|
December
31,
|
|||||||
2009
|
2008
|
|||||||
ASSETS
|
||||||||
Current
Assets
|
||||||||
Cash
and Cash Equivalents
|
$ |
926
|
$ |
1,140
|
||||
Accounts
Receivable, Net
|
348
|
423
|
||||||
Commodity
Derivative Assets, Current
|
96
|
437
|
||||||
Other
Current Assets
|
130
|
158
|
||||||
Total
Assets, Current
|
1,500
|
2,158
|
||||||
Property,
Plant and Equipment
|
||||||||
Oil
and Gas Properties (Successful Efforts Method of
Accounting)
|
12,364
|
11,963
|
||||||
Property,
Plant and Equipment, Other
|
228
|
175
|
||||||
Total
Property, Plant and Equipment, Gross
|
12,592
|
12,138
|
||||||
Accumulated
Depreciation, Depletion and Amortization
|
(3,696
|
) |
(3,134
|
) | ||||
Total
Property, Plant and Equipment, Net
|
8,896
|
9,004
|
||||||
Goodwill
|
758
|
759
|
||||||
Other
Noncurrent Assets
|
481
|
463
|
||||||
Total
Assets
|
$ |
11,635
|
$ |
12,384
|
||||
LIABILITIES
AND SHAREHOLDERS’ EQUITY
|
||||||||
Current
Liabilities
|
||||||||
Accounts
Payable - Trade
|
$ |
397
|
$ |
579
|
||||
Income
Taxes Payable
|
137
|
130
|
||||||
Deferred
Income Taxes, Net, Current
|
1
|
142
|
||||||
Other
Current Liabilities
|
311
|
323
|
||||||
Total
Liabilities, Current
|
846
|
1,174
|
||||||
Long-Term
Debt
|
2,161
|
2,241
|
||||||
Deferred
Income Taxes, Noncurrent
|
1,905
|
2,174
|
||||||
Other
Noncurrent Liabilities
|
565
|
486
|
||||||
Total
Liabilities
|
5,477
|
6,075
|
||||||
Commitments
and Contingencies
|
||||||||
|
||||||||
Shareholders’
Equity
|
||||||||
Preferred
Stock - Par Value $1.00; 4 million Shares Authorized, None
Issued
|
-
|
-
|
||||||
Common
Stock - Par Value $3.33 1/3; 250 Million Shares Authorized; 193
Million and 192 Million Shares Issued, Respectively
|
645
|
641
|
||||||
Additional
Paid in Capital
|
2,244
|
2,193
|
||||||
Accumulated
Other Comprehensive Loss
|
(82
|
) |
(110
|
) | ||||
Treasury
Stock, at Cost; 19 Million Shares
|
(615
|
) |
(614
|
) | ||||
Retained
Earnings
|
3,966
|
4,199
|
||||||
Total
Shareholders’ Equity
|
6,158
|
6,309
|
||||||
Total
Liabilities and Shareholders’ Equity
|
$ |
11,635
|
$ |
12,384
|
||||
The
accompanying notes are an integral part of these financial
statements.
|
Nine
Months Ended
September
30,
|
||||||||
2009
|
2008
|
|||||||
Cash
Flows From Operating Activities
|
||||||||
Net
Income (Loss)
|
$ | (139 | ) | $ | 1,045 | |||
Adjustments
to Reconcile Net Income (Loss) to Net Cash Provided by Operating
Activities:
|
||||||||
Depreciation,
Depletion and Amortization
|
601 | 593 | ||||||
Asset
Impairments
|
437 | 38 | ||||||
Deferred
Income Taxes
|
(443 | ) | 173 | |||||
Income
from Equity Method Investees
|
(52 | ) | (158 | ) | ||||
Dividends
from Equity Method Investees
|
37 | 192 | ||||||
Unrealized
(Gain) Loss on Commodity Derivative Instruments
|
508 | (9 | ) | |||||
Settlement
of Previously Recognized Hedge Losses
|
- | (144 | ) | |||||
Allowance
for Doubtful Accounts
|
(22 | ) | 47 | |||||
Gain
on Asset Sale
|
(24 | ) | - | |||||
Other
Adjustments for Noncash Items Included in Income
|
72 | 99 | ||||||
Changes
in Operating Assets and Liabilities:
|
||||||||
(Increase)
Decrease in Accounts Receivable
|
92 | (94 | ) | |||||
(Increase)
Decrease in Other Current Assets
|
25 | (19 | ) | |||||
(Decrease)
in Accounts Payable
|
(65 | ) | (135 | ) | ||||
Increase
in Other Current Liabilities
|
10 | 235 | ||||||
Other
Assets and Liabilities, Net
|
(51 | ) | 4 | |||||
Net
Cash Provided by Operating Activities
|
986 | 1,867 | ||||||
|
||||||||
Cash
Flows From Investing Activities
|
||||||||
Additions
to Property, Plant and Equipment
|
(1,012 | ) | (1,852 | ) | ||||
Proceeds
from Sale of Property, Plant and Equipment
|
- | 131 | ||||||
Net
Cash Used in Investing Activities
|
(1,012 | ) | (1,721 | ) | ||||
|
||||||||
Cash
Flows From Financing Activities
|
||||||||
Exercise
of Stock Options
|
15 | 26 | ||||||
Excess
Tax Benefits from Stock-Based Awards
|
3 | 23 | ||||||
Dividends
Paid, Common Stock
|
(94 | ) | (84 | ) | ||||
Purchase
of Treasury Stock
|
(1 | ) | (2 | ) | ||||
Proceeds
from Credit Facilities
|
340 | 650 | ||||||
Repayment
of Credit Facilities
|
(1,411 | ) | (425 | ) | ||||
Net
Proceeds from Issuance of 8 ¼% Senior Notes
|
989 | - | ||||||
Repayment
of Installment Note
|
(25 | ) | (25 | ) | ||||
Repurchase
of Senior Debentures
|
(4 | ) | - | |||||
Proceeds
from Short Term Borrowings
|
- | 23 | ||||||
Net
Cash Provided by (Used in) Financing Activities
|
(188 | ) | 186 | |||||
Increase
(Decrease) in Cash and Cash Equivalents
|
(214 | ) | 332 | |||||
Cash
and Cash Equivalents at Beginning of Period
|
1,140 | 660 | ||||||
Cash
and Cash Equivalents at End of Period
|
$ | 926 | $ | 992 | ||||
The
accompanying notes are an integral part of these financial
statements.
|
Nine
Months Ended
September
30,
|
||||||||
2009
|
2008
|
|||||||
Common
Stock
|
||||||||
Balance,
Beginning of Period
|
$ | 641 | $ | 636 | ||||
Exercise
of Stock Options
|
2 | 4 | ||||||
Restricted
Stock Awards, Net
|
2 | 1 | ||||||
Balance,
End of Period
|
645 | 641 | ||||||
Capital
in Excess of Par Value
|
||||||||
Balance,
Beginning of Period
|
2,193 | 2,106 | ||||||
Stock-Based
Compensation Expense
|
37 | 30 | ||||||
Exercise
of Stock Options
|
13 | 22 | ||||||
Tax
Benefits Related to Exercise of Stock Options
|
3 | 23 | ||||||
Restricted
Stock Awards, Net
|
(2 | ) | (1 | ) | ||||
Rabbi
Trust Shares Sold
|
- | 2 | ||||||
Balance,
End of Period
|
2,244 | 2,182 | ||||||
Accumulated
Other Comprehensive Loss
|
||||||||
Balance,
Beginning of Period
|
(110 | ) | (284 | ) | ||||
Oil
and Gas Cash Flow Hedges:
|
||||||||
Realized
Amounts Reclassified Into Earnings
|
28 | 155 | ||||||
Balance,
End of Period
|
(82 | ) | (129 | ) | ||||
Treasury
Stock at Cost
|
||||||||
Balance,
Beginning of Period
|
(614 | ) | (613 | ) | ||||
Purchases
of Treasury Stock
|
(1 | ) | (2 | ) | ||||
Rabbi
Trust Shares Sold
|
- | 1 | ||||||
Balance,
End of Period
|
(615 | ) | (614 | ) | ||||
Retained
Earnings
|
||||||||
Balance,
Beginning of Period
|
4,199 | 2,964 | ||||||
Net
Income (Loss)
|
(139 | ) | 1,045 | |||||
Cash
Dividends ($0.54 Per Share and $0.48 Per Share,
Respectively)
|
(94 | ) | (84 | ) | ||||
Balance,
End of Period
|
3,966 | 3,925 | ||||||
Total
Shareholders' Equity
|
$ | 6,158 | $ | 6,005 | ||||
The
accompanying notes are an integral part of these financial
statements.
|
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Other
Revenues
|
||||||||||||||||
Electricity
Sales (1)
|
$ | 20 | $ | 14 | $ | 51 | $ | 42 | ||||||||
Gathering,
Marketing and Processing (GMP) Revenues
|
3 | 4 | 10 | 13 | ||||||||||||
Total
|
$ | 23 | $ | 18 | $ | 61 | $ | 55 | ||||||||
Other
Operating (Income) Expense, Net
|
||||||||||||||||
Gain
on Asset Sale (2)
|
$ | - | $ | (8 | ) | $ | (24 | ) | $ | (8 | ) | |||||
Electricity
Generation Expense (1)
|
19 | 13 | - | 41 | ||||||||||||
GMP
Expense
|
5 | 5 | 15 | 14 | ||||||||||||
Settlement
of Legal Proceedings (3)
|
- | - | 9 | - | ||||||||||||
(Gain)
Loss on Involuntary Conversion (4)
|
- | 9 | (4 | ) | 9 | |||||||||||
Other,
Net (5)
|
10 | 41 | 26 | 51 | ||||||||||||
Total
|
$ | 34 | $ | 60 | $ | 22 | $ | 107 | ||||||||
Other
Non-Operating (Income) Expense, Net
|
||||||||||||||||
Deferred
Compensation (Income) Expense (6)
|
$ | 7 | $ | (47 | ) | $ | 18 | $ | (25 | ) | ||||||
Interest
Income
|
(1 | ) | (6 | ) | (2 | ) | (18 | ) | ||||||||
Other
(Income) Expense, Net
|
(1 | ) | 1 | 2 | 1 | |||||||||||
Total
|
$ | 5 | $ | (52 | ) | $ | 18 | $ | (42 | ) |
(1)
|
Includes
amounts related to our 100%-owned Ecuador integrated power project. The
project includes the Amistad natural gas field, offshore Ecuador, which
supplies natural gas to fuel the Machala power plant located in Machala,
Ecuador. Electricity generation expense includes all operating and
non-operating expenses associated with the plant, including depreciation,
depletion and amortization expense (DD&A) and changes in the
allowance for doubtful accounts. We recognized a net increase of $4
million in the allowance during third quarter 2009 and a net decrease of
$36 million in the allowance during the first nine months of 2009. We
recognized net increases of $3 million and $9 million in the allowance
during the third quarter and first nine months of 2008, respectively. See
Allowance
for Doubtful Accounts below.
|
(2)
|
In
February 2008, effective July 1, 2007, we sold our interest in Argentina
for a sales price of $117.5 million. The gain on sale was deferred until
second quarter 2009 when the Argentine government approved the
sale.
|
(3)
|
Amount
for the first nine months of 2009 includes a $19 million charge on legal
settlement, offset by a $15 million gain on legal settlement related to
reimbursement of bonuses paid for federal leases offshore
California.
|
(4)
|
Amount
for the first nine months of 2009 represents final receipt of insurance
claims related to Hurricanes Katrina and Rita damage. Amount for the first
nine months of 2008 represents interim settlement of the replacement cost
portion of the Hurricane Katrina insurance
claim.
|
(5)
|
Includes
write-downs of SemCrude L.P. receivable of $12 million in third quarter
2009 and $38 million in third quarter 2008. See Allowance for Doubtful
Accounts below and Note 14 – Commitments and
Contingencies.
|
(6)
|
Amount
represents increases or (decreases) in the fair value of Noble Energy
common stock held in a rabbi trust.
|
Balance Sheet Information
– Other balance sheet information is as
follows:
|
September
30,
|
December
31,
|
||||||
2009
|
2008
|
||||||
(in
millions)
|
|||||||
Other
Current Assets
|
|||||||
Inventories,
Current
|
$ |
101
|
$ |
105
|
|||
Prepaid
Expenses and Other Assets, Current
|
29
|
27
|
|||||
Asset
Held for Sale (1)
|
-
|
26
|
|||||
Total
|
$ |
130
|
$ |
158
|
|||
Other
Noncurrent Assets
|
|||||||
Equity
Method Investments
|
$ |
329
|
$ |
311
|
|||
Mutual
Fund Investments
|
103
|
84
|
|||||
Commodity
Derivative Assets, Noncurrent
|
-
|
33
|
|||||
Other
Assets, Noncurrent
|
49
|
35
|
|||||
Total
|
$ |
481
|
$ |
463
|
(1)
|
The
Main Pass asset was reclassified as held-and-used and impaired during
first quarter 2009. Estimated proved reserves attributed to this property
were less than 1% of our total estimated proved reserves. See Note 5 – Fair Value
Measurements and Disclosures.
|
September
30,
|
December
31,
|
||||||
2009
|
2008
|
||||||
(in
millions)
|
|||||||
Other
Current Liabilities
|
|||||||
Production
and Ad Valorem Taxes
|
$ |
116
|
$ |
114
|
|||
Commodity
Derivative Liabilities, Current
|
58
|
23
|
|||||
Asset
Retirement Obligations, Current
|
44
|
27
|
|||||
Interest
Payable
|
24
|
9
|
|||||
Short-Term
Borrowings
|
-
|
25
|
|||||
Deferred
Gain on Asset Sale, Current (1)
|
-
|
24
|
|||||
Other
|
69
|
101
|
|||||
Total
|
$ |
311
|
$ |
323
|
|||
Other
Noncurrent Liabilities
|
|||||||
Deferred
Compensation Liabilities, Noncurrent
|
$ |
202
|
$ |
159
|
|||
Asset
Retirement Obligations, Noncurrent
|
184
|
184
|
|||||
Accrued
Benefit Costs, Noncurrent
|
71
|
81
|
|||||
Commodity
Derivative Liabilities, Noncurrent
|
56
|
2
|
|||||
Other
Liabilities, Noncurrent
|
52
|
60
|
|||||
Total
|
$ |
565
|
$ |
486
|
(1)
|
See
footnote (2) to Statements of Operations
Information above.
|
·
|
descibes how to determine the fair value of assets and liabilities in the current economic environment and reemphasizes that the objective of a fair value measurement remains the price that would be received to sell an asset or paid to transfer a liability at the measurement date. |
·
|
modifies
the requirements for recognizing other-than-temporarily impaired debt
securities and significantly changes the existing impairment model for
such securities. It also modifies the presentation of other-than-temporary
impairment losses and increases the frequency of and expands already
required disclosures about other-than-temporary impairment for debt and
equity securities.
|
·
|
requires
disclosures of the fair value of financial instruments in interim
financial statements, the method or methods and significant assumptions
used to estimate the fair value of financial instruments, and a discussion
of changes, if any, in the method or methods and significant assumptions
during the period.
|
·
|
the
period after the balance sheet date during which management of a reporting
entity should evaluate events or transactions that may occur for potential
recognition or disclosure in the financial statements (through the date
that the financial statements are issued or are available to be
issued);
|
·
|
the
circumstances under which an entity should recognize events or
transactions occurring after the balance sheet date in its financial
statements; and
|
·
|
the
disclosures that an entity should make about events or transactions that
occurred after the balance sheet
date.
|
September
30,
|
December
31,
|
|||||||||||||||
2009
|
2008
|
|||||||||||||||
Debt
|
Interest
Rate
|
Debt
|
Interest
Rate
|
|||||||||||||
(in
millions, except percentages)
|
||||||||||||||||
Credit
Facility
|
$ | 535 | 0.56 | % | $ | 1,606 | 0.80 | % | ||||||||
5
¼% Senior Notes, due April 15, 2014
|
200 | 5.25 | % | 200 | 5.25 | % | ||||||||||
8
¼% Senior Notes, due March 1, 2019
|
1,000 | 8.25 | % | - | - | |||||||||||
7
¼% Notes, due October 15, 2023
|
100 | 7.25 | % | 100 | 7.25 | % | ||||||||||
8%
Senior Notes, due April 1, 2027
|
250 | 8.00 | % | 250 | 8.00 | % | ||||||||||
7
¼% Senior Debentures, due August 1, 2097
|
84 | 7.25 | % | 89 | 7.25 | % | ||||||||||
Long-term
Debt
|
2,169 | 2,245 | ||||||||||||||
Installment
Payment, due May 11, 2009
|
- | - | 25 | 4.18 | % | |||||||||||
Total
Debt
|
2,169 | 2,270 | ||||||||||||||
Unamortized
Discount
|
(8 | ) | (4 | ) | ||||||||||||
Total
Debt, Net of Discount
|
$ | 2,161 | $ | 2,266 |
Variable
to Fixed Price Swaps
|
Collars
|
|||||||||||||||||||||||||
Weighted
|
Weighted
|
Weighted
|
||||||||||||||||||||||||
Production
|
Bbls
|
Average
|
Bbls
|
Average
|
Average
|
|||||||||||||||||||||
Period
|
Index
|
Per
Day
|
Fixed
Price
|
Index
|
Per
Day
|
Floor
Price
|
Ceiling
Price
|
|||||||||||||||||||
4th
Qtr 2009
|
NYMEX
WTI
|
9,000 | $ | 88.43 |
NYMEX
WTI
|
6,700 | $ | 79.70 | $ | 90.60 | ||||||||||||||||
4th
Qtr 2009
|
Dated
Brent
|
2,000 | 87.98 |
Dated
Brent
|
4,848 | 71.82 | 88.66 | |||||||||||||||||||
4th
Qtr 2009 Average
|
11,000 | 88.35 | 11,548 | 76.39 | 89.79 | |||||||||||||||||||||
2010
|
- | - | - |
NYMEX
WTI
|
14,500 | 61.48 | 75.63 | |||||||||||||||||||
2010
|
Dated
Brent
|
1,000 | 80.05 |
Dated
Brent
|
7,000 | 64.00 | 73.96 | |||||||||||||||||||
2010
Average
|
1,000 | 80.05 | 21,500 | 62.30 | 75.09 | |||||||||||||||||||||
2011
|
- | - | - |
NYMEX
WTI
|
1,000 | 70.00 | 82.40 |
Variable
to Fixed Price Swaps
|
Collars
|
|||||||||||||||||||||||||
Weighted
|
Weighted
|
Weighted
|
||||||||||||||||||||||||
Production
|
MMBtu
|
Average
|
MMBtu
|
Average
|
Average
|
|||||||||||||||||||||
Period
|
Index
|
Per
Day
|
Fixed
Price
|
Index
|
Per
Day
|
Floor
Price
|
Ceiling
Price
|
|||||||||||||||||||
4th
Qtr 2009
|
- | - | - |
NYMEX
HH (1)
|
170,000 | $ | 9.15 | $ | 10.81 | |||||||||||||||||
4th
Qtr 2009
|
- | - | - |
IFERC
CIG (2)
|
15,000 | 6.00 | 9.90 | |||||||||||||||||||
4th
Qtr 2009 Average
|
- | - | 185,000 | 8.90 | 10.73 | |||||||||||||||||||||
2010
|
NYMEX
HH
|
20,000 | 6.10 |
NYMEX
HH
|
210,000 | 5.90 | 6.73 | |||||||||||||||||||
2010
|
- | - | - |
IFERC
CIG
|
15,000 | 6.25 | 8.10 | |||||||||||||||||||
2010
Average
|
20,000 | 6.10 | 225,000 | 5.93 | 6.82 | |||||||||||||||||||||
2011
|
- | - | - |
NYMEX
HH
|
140,000 | 5.95 | 6.82 |
(1)
|
Henry
Hub
|
(2)
|
Colorado
Interstate Gas – Northern System
|
Basis
Swaps
|
|||||||||||||
Weighted
|
|||||||||||||
Production
|
Index
Less
|
MMBtu
|
Average
|
||||||||||
Period
|
Index
|
Differential
|
Per
Day
|
Differential
|
|||||||||
4th
Qtr 2009
|
IFERC
CIG
|
NYMEX
HH
|
140,000 | $ | (2.49 | ) | |||||||
2010
|
IFERC
CIG
|
NYMEX
HH
|
100,000 | (1.60 | ) | ||||||||
2011
|
IFERC
CIG
|
NYMEX
HH
|
80,000 | (0.84 | ) |
Derivative
Instruments Not Designated as Hedging Instruments
|
|||||||||||||||||||||
Asset Derivative Instruments | Liability Derivative Instruments | ||||||||||||||||||||
September
30,
|
December
31,
|
September
30,
|
December
31,
|
||||||||||||||||||
2009
|
2008
|
2009
|
2008
|
||||||||||||||||||
(in
millions)
|
Balance
Sheet
Location
|
Fair
Value
|
Balance
Sheet
Location
|
Fair
Value
|
Balance
Sheet
Location
|
Fair
Value
|
Balance
Sheet
Location
|
Fair
Value
|
|||||||||||||
Commodity
Derivative Instruments
|
|||||||||||||||||||||
Current
Assets
|
$ | 96 |
Current
Assets
|
$ | 437 |
Current
Liabilities
|
$ | 58 |
Current
Liabilities
|
$ | 23 | ||||||||||
Noncurrent
Assets
|
- |
Noncurrent
Assets
|
33 |
Noncurrent
Liabilities
|
56 |
Noncurrent
Liabilities
|
2 | ||||||||||||||
Total
|
$ | 96 | $ | 470 | $ | 114 | $ | 25 |
Derivative
Instruments Not Designated as Hedging Instruments
|
||||||||||||||||
Amount
of (Gain) Loss on Derivative
Instruments
Recognized in Income
|
||||||||||||||||
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Commodity
Derivative Instruments
|
||||||||||||||||
Realized
Mark-to-Market (Gain) Loss
(1)
|
$ |
(121
|
) | $ |
68
|
$ |
(413
|
) | $ |
199
|
||||||
Unrealized
Mark-to-Market (Gain) Loss (1)
|
149
|
(943
|
) |
508
|
(9
|
) | ||||||||||
Total
(Gain) Loss on Commodity Derivative Instruments
|
$ |
28
|
$ |
(875
|
) | $ |
95
|
$ |
190
|
(1)
|
Amounts
are recognized as (Gain) Loss on Commodity Derivative Instruments in our
consolidated statements of
operations.
|
Derivative
Instruments in Previously Designated Cash Flow Hedging
Relationships
|
||||||||||||||||
Amount
of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive
Income
|
Amount
of (Gain) Loss on Derivative Instruments Reclassified from Accumulated
Other Comprehensive Loss
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions)
|
(in
millions)
|
|||||||||||||||
Three
Months Ended September 30,
|
||||||||||||||||
Commodity
Derivative Instruments (1)
|
||||||||||||||||
Crude
Oil
(2)
|
$ | - | $ | - | $ | 14 | $ | 89 | ||||||||
Natural
Gas (2)
|
- | - | - | 4 | ||||||||||||
Treasury
Rate Locks
|
- | (12 | ) | - | - | |||||||||||
Total
|
$ | - | $ | (12 | ) | $ | 14 | $ | 93 | |||||||
Nine
Months Ended September 30,
|
||||||||||||||||
Commodity
Derivative Instruments (1)
|
||||||||||||||||
Crude
Oil
(2)
|
$ | - | $ | - | $ | 45 | $ | 279 | ||||||||
Natural
Gas (2)
|
- | - | - | (31 | ) | |||||||||||
Treasury
Rate Locks
|
- | (1 | ) | - | - | |||||||||||
Total
|
$ | - | $ | (1 | ) | $ | 45 | $ | 248 |
(1)
|
Includes
effect of commodity derivative instruments previously accounted for as
cash flow hedges. Net derivative gains and losses that were deferred in
AOCL as of January 1, 2008, as a result of previous cash flow hedge
accounting, are reclassified to earnings in future periods as the original
hedged transactions occur.
|
(2)
|
The
amount of (Gain) Loss reclassified from AOCL on Derivative Instruments is
recognized in Oil, Gas and NGL Sales within our consolidated
statements of operations.
|
Fair
Value Measurements Using
|
||||||||||||||||
Quoted
Prices in
Active
Markets (Level 1)
|
Significant
Other Observable Inputs (Level 2)
|
Significant Unobservable Inputs (Level 3) |
Adjustment
(1)
|
Fair Value Measurement | ||||||||||||
(in
millions)
|
||||||||||||||||
As
of September 30, 2009
|
||||||||||||||||
Financial
Assets:
|
||||||||||||||||
Mutual
Fund Investments
|
$ |
103
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
103
|
||||||
Commodity
Derivative Instruments
|
-
|
127
|
-
|
(31
|
) |
96
|
||||||||||
Financial
Liabilities:
|
||||||||||||||||
Commodity
Derivative Instruments
|
-
|
(145
|
) |
-
|
31
|
(114
|
) | |||||||||
Patina
Deferred Compensation Liability
|
(158
|
) |
-
|
-
|
-
|
(158
|
) | |||||||||
As
of December 31, 2008
|
||||||||||||||||
Financial
Assets:
|
||||||||||||||||
Mutual
Fund Investments
|
$ |
84
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
84
|
||||||
Commodity
Derivative Instruments
|
-
|
492
|
-
|
(22
|
) |
470
|
||||||||||
Financial
Liabilities:
|
||||||||||||||||
Commodity
Derivative Instruments
|
-
|
(47
|
) |
-
|
22
|
(25
|
) | |||||||||
Patina
Deferred Compensation Liability
|
(123
|
) |
-
|
-
|
-
|
(123
|
) |
(1)
Amount represents the impact of master netting agreements that
allow us to net cash settle asset and liability positions with the same
counterparty.
|
September
30,
|
December
31,
|
|||||||||||||||
2009
|
2008
|
|||||||||||||||
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Total
Debt, Net of Unamortized Discount
|
$ | 2,161 | $ | 2,418 | $ | 2,266 | $ | 2,172 |
Nine
Months Ended September 30, 2009
|
||||
(in
millions)
|
||||
Capitalized
Exploratory Well Costs, Beginning of Period
|
$ |
501
|
||
Additions
to Capitalized Exploratory Well Costs Pending Determination of Proved
Reserves
|
101
|
|||
Reclassified
to Property, Plant and Equipment Based on Determination of Proved
Reserves
|
(198
|
) | ||
Capitalized
Exploratory Well Costs Charged to Expense
|
(7
|
) | ||
Capitalized
Exploratory Well Costs, End of Period
|
$ |
397
|
September
30,
|
December
31,
|
|||||||
2009
|
2008
|
|||||||
(in
millions)
|
||||||||
Exploratory
Well Costs Capitalized for a Period of One Year or Less
|
$ | 116 | $ | 256 | ||||
Exploratory
Well Costs Capitalized for a Period Greater Than One Year After Completion
of Drilling
|
281 | 245 | ||||||
Balance
at End of Period
|
$ | 397 | $ | 501 | ||||
Number
of Projects with Exploratory Well Costs That Have Been Capitalized for a
Period Greater Than One Year After Completion of Drilling
|
5 | 6 |
Suspended
Since
|
||||||||||||||||
Total
|
2008
|
2007
|
2006
&
Prior
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Project
|
||||||||||||||||
West
Africa
|
$ | 179 | $ | 69 | $ | 96 | $ | 14 | ||||||||
Gunflint
(deepwater Gulf of Mexico)
|
48 | 48 | - | - | ||||||||||||
Redrock
(deepwater Gulf of Mexico)
|
17 | - | - | 17 | ||||||||||||
Flyndre
(North Sea)
|
15 | - | 12 | 3 | ||||||||||||
Selkirk
(North Sea)
|
22 | - | 22 | - | ||||||||||||
Total
Exploratory Well Costs Capitalized for a Period Greater Than One Year
After Completion of Drilling
|
$ | 281 | $ | 117 | $ | 130 | $ | 34 |
Nine
Months Ended
September
30,
|
||||||||
2009
|
2008
|
|||||||
(in millions) | ||||||||
Asset
Retirement Obligations, Beginning of Period
|
$ | 211 | $ | 144 | ||||
Liabilities
Incurred in Current Period
|
6 | 15 | ||||||
Liabilities
Settled in Current Period
|
(23 | ) | (16 | ) | ||||
Revisions
|
23 | 10 | ||||||
Accretion
Expense
|
11 | 7 | ||||||
Asset
Retirement Obligations, End of Period
|
$ | 228 | $ | 160 |
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Service
Cost
|
$ | 3 | $ | 3 | $ | 9 | $ | 9 | ||||||||
Interest
Cost
|
3 | 3 | 9 | 9 | ||||||||||||
Expected
Return on Plan Assets
|
(3 | ) | (3 | ) | (10 | ) | (9 | ) | ||||||||
Other
|
- | 1 | 1 | 2 | ||||||||||||
Net
Periodic Benefit Cost
|
$ | 3 | $ | 4 | $ | 9 | $ | 11 |
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Stock-Based
Compensation Expense
|
$ | 13 | $ | 10 | $ | 37 | $ | 30 | ||||||||
Tax
Benefit Recognized
|
(5 | ) | (4 | ) | (13 | ) | (11 | ) |
Three
Months Ended
|
Nine
Months Ended
|
|||||||||||||||
September
30,
|
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions, except per share amounts)
|
||||||||||||||||
Net
Income (Loss)
|
$ | 107 | $ | 974 | $ | (139 | ) | $ | 1,045 | |||||||
Earnings
Adjustment from Assumed Conversion of
|
||||||||||||||||
Dilutive
Shares of Common Stock in Rabbi Trust (1)
|
- | (29 | ) | - | (16 | ) | ||||||||||
Net
Income (Loss) Used for Diluted Earnings Per Share
Calculation
|
$ | 107 | $ | 945 | $ | (139 | ) | $ | 1,029 | |||||||
Weighted
Average Number of Shares Outstanding, Basic
|
173 | 173 | 173 | 172 | ||||||||||||
Incremental
Shares from Assumed Conversion of
|
||||||||||||||||
Dilutive
Options, Restricted Stock and Shares of Common Stock in Rabbi
Trust
|
2 | 3 | - | 4 | ||||||||||||
Weighted
Average Number of Shares Outstanding, Diluted
|
175 | 176 | 173 | 176 | ||||||||||||
Earnings
(Loss) Per Share, Basic
|
$ | 0.62 | $ | 5.64 | $ | (0.80 | ) | $ | 6.06 | |||||||
Earnings
(Loss) Per Share, Diluted
|
$ | 0.61 | $ | 5.37 | $ | (0.80 | ) | $ | 5.86 |
(1)
|
The
diluted earnings per share calculation for the three and nine months ended
September 30, 2008 includes decreases to net income of $29 million and $16
million (net of tax), respectively, related to a deferred compensation
gain from Noble Energy shares held in a rabbi trust. When dilutive, the
deferred compensation gain or loss (net of tax) is excluded from net
income while the Noble Energy shares held in the rabbi trust are included
in the diluted share count.
|
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Current
|
$ | 92 | $ | 316 | $ | 233 | $ | 355 | ||||||||
Deferred
|
(84 | ) | 164 | (443 | ) | 173 | ||||||||||
Total
Income Tax Provision (Benefit)
|
$ | 8 | $ | 480 | $ | (210 | ) | $ | 528 |
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Net
Income (Loss)
|
$ | 107 | $ | 974 | $ | (139 | ) | $ | 1,045 | |||||||
Other
Items of Comprehensive Income (Loss)
|
||||||||||||||||
Oil
and Gas Cash Flow Hedges
|
||||||||||||||||
Realized
Losses Reclassified Into Earnings
|
14 | 93 | 45 | 248 | ||||||||||||
Less
Tax Provision
|
(5 | ) | (35 | ) | (17 | ) | (93 | ) | ||||||||
Interest
Rate Cash Flow Hedges
|
||||||||||||||||
Unrealized
Gain in Fair Value
|
- | 12 | - | 1 | ||||||||||||
Less
Tax Provision
|
- | (5 | ) | - | - | |||||||||||
Net
Change in Other
|
- | - | - | (1 | ) | |||||||||||
Other
Comprehensive Income
|
9 | 65 | 28 | 155 | ||||||||||||
Comprehensive
Income (Loss)
|
$ | 116 | $ | 1,039 | $ | (111 | ) | $ | 1,200 |
Consolidated
|
United
States
|
West
Africa
|
North
Sea
|
Eastern
Mediter-ranean
|
Other
Int'l, Corporate, Marketing (1)
|
|||||||||||||||||||
(in
millions)
|
||||||||||||||||||||||||
Three
Months Ended September 30, 2009
|
||||||||||||||||||||||||
Revenues
from Third Parties
|
$ | 610 | $ | 332 | $ | 95 | $ | 51 | $ | 53 | $ | 79 | ||||||||||||
Reclassification
from AOCL (2)
|
(14 | ) | (7 | ) | (7 | ) | - | - | - | |||||||||||||||
Intersegment
Revenue
|
- | 33 | - | - | - | (33 | ) | |||||||||||||||||
Income
from Equity Method Investees
|
25 | - | 25 | - | - | - | ||||||||||||||||||
Total
Revenues
|
621 | 358 | 113 | 51 | 53 | 46 | ||||||||||||||||||
DD&A
|
205 | 172 | 9 | 10 | 6 | 8 | ||||||||||||||||||
Loss
(gain) on Commodity Derivative Instruments
|
28 | 34 | (6 | ) | - | - | - | |||||||||||||||||
Income
(Loss) Before Income Taxes
|
115 | 42 | 94 | 25 | 43 | (89 | ) | |||||||||||||||||
Three
Months Ended September 30, 2008
|
||||||||||||||||||||||||
Revenues
from Third Parties
|
$ | 1,151 | $ | 646 | $ | 156 | $ | 136 | $ | 51 | $ | 162 | ||||||||||||
Reclassification
from AOCL (2)
|
(93 | ) | (84 | ) | (9 | ) | - | - | - | |||||||||||||||
Intersegment
Revenue
|
- | 112 | - | - | - | (112 | ) | |||||||||||||||||
Income
from Equity Method Investees
|
40 | - | 40 | - | - | - | ||||||||||||||||||
Total
Revenues
|
1,098 | 674 | 187 | 136 | 51 | 50 | ||||||||||||||||||
DD&A
|
194 | 158 | 8 | 12 | 7 | 9 | ||||||||||||||||||
Asset
Impairments
|
38 | 38 | - | - | - | - | ||||||||||||||||||
(Gain)
on Commodity Derivative Instruments
|
(875 | ) | (749 | ) | (126 | ) | - | - | - | |||||||||||||||
Income
(Loss) Before Income Taxes
|
1,454 | 1,058 | 303 | 107 | 40 | (54 | ) | |||||||||||||||||
Consolidated
|
United
States
|
West
Africa
|
North
Sea
|
Eastern
Mediter-ranean
|
Other
Int'l, Corporate, Marketing (1)
|
|||||||||||||||||||
(in
millions)
|
||||||||||||||||||||||||
Nine
Months Ended September 30, 2009
|
||||||||||||||||||||||||
Revenues
from Third Parties
|
$ | 1,546 | $ | 843 | $ | 238 | $ | 120 | $ | 105 | $ | 240 | ||||||||||||
Reclassification
from AOCL (2)
|
(45 | ) | (23 | ) | (22 | ) | - | - | - | |||||||||||||||
Intersegment
Revenue
|
- | 121 | - | - | - | (121 | ) | |||||||||||||||||
Income
from Equity Method Investees
|
52 | - | 52 | - | - | - | ||||||||||||||||||
Total
Revenues
|
1,553 | 941 | 268 | 120 | 105 | 119 | ||||||||||||||||||
DD&A
|
601 | 505 | 27 | 28 | 16 | 25 | ||||||||||||||||||
Asset
Impairments
|
437 | 437 | - | - | - | - | ||||||||||||||||||
Loss
on Commodity Derivative Instruments
|
95 | 76 | 19 | - | - | - | ||||||||||||||||||
Income
(Loss) Before Income Taxes
|
(349 | ) | (439 | ) | 176 | 49 | 77 | (212 | ) | |||||||||||||||
Nine
Months Ended September 30, 2008
|
||||||||||||||||||||||||
Revenues
from Third Parties
|
$ | 3,418 | $ | 1,975 | $ | 460 | $ | 327 | $ | 121 | $ | 535 | ||||||||||||
Reclassification
from AOCL (2)
|
(248 | ) | (216 | ) | (32 | ) | - | - | - | |||||||||||||||
Intersegment
Revenue
|
- | 372 | - | - | - | (372 | ) | |||||||||||||||||
Income
from Equity Method Investees
|
158 | - | 158 | - | - | - | ||||||||||||||||||
Total
Revenues
|
3,328 | 2,131 | 586 | 327 | 121 | 163 | ||||||||||||||||||
DD&A
|
593 | 487 | 26 | 40 | 18 | 22 | ||||||||||||||||||
Asset
Impairments
|
38 | 38 | - | - | - | - | ||||||||||||||||||
Loss
on Commodity Derivative Instruments
|
190 | 137 | 53 | - | - | - | ||||||||||||||||||
Income
(Loss) Before Income Taxes
|
1,573 | 990 | 491 | 234 | 94 | (236 | ) | |||||||||||||||||
Total
Assets at September 30, 2009
(3)
|
$ | 11,635 | $ | 8,557 | $ | 1,667 | $ | 605 | $ | 426 | $ | 380 | ||||||||||||
Total
Assets at December 31, 2008 (3)
|
12,384 | 9,212 | 1,614 | 775 | 366 | 417 |
(1)
|
Other
international includes China, Ecuador and Argentina (through February
2008) operations and the gain on sale of Argentina (in
2009).
|
(2)
|
Revenues
include decreases resulting from hedging activities. The decreases
resulted from hedge gains and losses that were deferred in AOCL, as a
result of previous cash flow hedge accounting, and subsequently
reclassified to revenues.
|
(3)
|
The
US reporting unit includes goodwill of $758 million at September 30, 2009
and $759 million at December 31,
2008.
|
Note 14 – Commitments
and Contingencies
|
|
·
|
Commodity
Prices – Economic producibility of reserves and discounted cash flows will
be based on a 12-month average commodity price unless contractual
arrangements designate the price to be
used.
|
|
·
|
Disclosure
of Unproved Reserves – Probable and possible reserves may be disclosed
separately on a voluntary basis.
|
|
·
|
Proved
Undeveloped Reserve Guidelines – Reserves may be classified as proved
undeveloped if there is a high degree of confidence that the quantities
will be recovered.
|
|
·
|
Reserve
Estimation Using New Technologies – Reserves may be estimated through the
use of reliable technology in addition to flow tests and production
history.
|
|
·
|
Reserve
Personnel and Estimation Process – Additional disclosure is required
regarding the qualifications of the chief technical person who oversees
our reserves estimation process. We will also be required to
provide a general discussion of our internal controls used to assure the
objectivity of the reserves
estimate.
|
|
·
|
Disclosure
by Geographic Area – Reserves in foreign countries or continents must be
presented separately if they represent more than 15% of our total oil and
gas proved reserves.
|
|
·
|
Non-Traditional
Resources – The
definition of oil and gas producing activities will expand and focus on
the marketable product rather than the method of
extraction.
|
|
·
|
net
income of $107 million, as compared with net income of $974 million for
third quarter 2008;
|
|
·
|
loss
on commodity derivative instruments of $28 million (including unrealized
mark-to-market loss of $149 million) as compared with a gain on commodity
derivative instruments of $875 million (including unrealized
mark-to-market gain of $943 million) for third quarter
2008;
|
|
·
|
diluted
earnings per share of $0.61, as compared with diluted earnings per share
of $5.37 for third quarter 2008;
|
|
·
|
ending
cash and cash equivalents balance of $926 million as compared with $1.1
billion at December 31, 2008; and
|
|
·
|
cash
flow provided by operating activities of $488 million, as compared with
$713 million for third quarter
2008.
|
Significant
operational highlights for third quarter 2009
included:
|
|
United
States – Offshore
|
|
·
|
Ticonderoga,
in the deepwater Gulf of Mexico, returned to
full production of approximately 5,000 Boepd, net
in August 2009 after being offline due to Hurricane Ike in
2008; and
|
|
·
|
approved
Isabela/Santa Cruz oil project in the deepwater Gulf of
Mexico.
|
|
United
States – Onshore
|
|
·
|
record
quarterly Wattenberg production of 283 MMcfepd, including liquid volumes
of 22 MBpd; and
|
|
·
|
completed
our first horizontal East Texas Haynesville shale well with an initial
thirty-day average production rate of over 11 MMcfpd,
gross.
|
|
International
|
|
·
|
sanctioned
Aseng field in Block I offshore Equatorial Guinea;
and
|
|
·
|
executed
an additional sales agreement in Israel which raised average natural
gas sales prices by over 40% from the previous
quarter.
|
|
·
|
overall
level and timing of capital expenditures, as discussed below, which,
dependent upon our drilling success, are expected to maintain our
near-term production volumes;
|
|
·
|
natural
field decline in the deepwater Gulf of Mexico, Gulf Coast and
Mid-continent areas of our US
operations;
|
|
·
|
downtime
beginning in mid-August at the Dumbarton field in the UK sector of the
North Sea due to FPSO repairs with an expected return to operation by the
end of October;
|
|
·
|
variations
in sales volumes of natural gas from the Alba field in Equatorial Guinea
related to potential downtime at the methanol, LPG and/or LNG
plants;
|
|
·
|
potential
hurricane-related volume curtailments in the Gulf of Mexico and Gulf Coast
areas as occurred with Hurricanes Gustav and Ike in
2008;
|
|
·
|
potential
winter storm-related volume curtailments in the Northern region of our US
operations;
|
|
·
|
potential
pipeline and processing facility capacity constraints in the Rocky
Mountains area of our US
operations;
|
|
·
|
Israeli
demand for electricity which affects demand for natural gas as fuel for
power generation, market growth and competing deliveries of natural gas
from Egypt;
|
|
·
|
seasonal
variations in rainfall in Ecuador that affect our natural gas-to-power
project; and
|
|
·
|
timing
of significant project completion and initial
production.
|
Crude
Oil
and
Condensate
|
Natural
Gas
|
NGLs
|
Total
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Three
Months Ended September 30,
|
||||||||||||||||
2008
Sales
|
$ | 629 | $ | 361 | $ | 50 | $ | 1,040 | ||||||||
Changes
due to:
|
||||||||||||||||
Sales
Volumes
|
(22 | ) | 18 | 3 | (1 | ) | ||||||||||
Sales
Prices
|
(305 | ) | (211 | ) | (29 | ) | (545 | ) | ||||||||
Amounts
Reclassified from AOCL
|
75 | 4 | - | 79 | ||||||||||||
2009
Sales
|
$ | 377 | $ | 172 | $ | 24 | $ | 573 | ||||||||
(Decrease)
from prior period
|
-40 | % | -52 | % | -52 | % | -45 | % | ||||||||
Nine
Months Ended September 30,
|
||||||||||||||||
2008
Sales
|
$ | 1,830 | $ | 1,132 | $ | 153 | $ | 3,115 | ||||||||
Changes
due to:
|
||||||||||||||||
Sales
Volumes
|
(215 | ) | 11 | 1 | (203 | ) | ||||||||||
Sales
Prices
|
(973 | ) | (614 | ) | (88 | ) | (1,675 | ) | ||||||||
Amounts
Reclassified from AOCL
|
234 | (31 | ) | - | 203 | |||||||||||
2009
Sales
|
$ | 876 | $ | 498 | $ | 66 | $ | 1,440 | ||||||||
(Decrease)
from prior period
|
-52 | % | -56 | % | -57 | % | -54 | % |
Sales
Volumes
|
Average
Realized Sales Prices
|
|||||||||||||||||||||||
Crude
Oil & Condensate (MBpd)
|
Natural
Gas (MMcfpd)
|
NGLs
(MBpd)
|
Crude
Oil & Condensate
(Per
Bbl)
|
Natural
Gas
(Per
Mcf)
|
NGLs
(Per
Bbl)
|
|||||||||||||||||||
Three
Months Ended September 30, 2009
|
||||||||||||||||||||||||
United
States (1)
(2)
|
39
|
397
|
10
|
$ |
62.30
|
$ |
3.05
|
$ |
25.39
|
|||||||||||||||
West
Africa (3)
(4)
|
14
|
228
|
-
|
63.10
|
0.27
|
-
|
||||||||||||||||||
North
Sea
|
8
|
5
|
-
|
69.56
|
4.63
|
-
|
||||||||||||||||||
Israel
|
-
|
144
|
-
|
-
|
3.95
|
-
|
||||||||||||||||||
Ecuador
(5)
|
-
|
28
|
-
|
-
|
-
|
-
|
||||||||||||||||||
Other
International
|
4
|
-
|
-
|
62.75
|
-
|
-
|
||||||||||||||||||
Total
Consolidated Operations
|
65
|
802
|
10
|
63.36
|
2.41
|
25.39
|
||||||||||||||||||
Equity
Investees (6)
|
2
|
-
|
6
|
66.33
|
-
|
38.26
|
||||||||||||||||||
Total
|
67
|
802
|
16
|
$ |
63.46
|
$ |
2.41
|
$ |
30.25
|
|||||||||||||||
Three
Months Ended September 30, 2008
|
||||||||||||||||||||||||
United
States (1)
(2)
|
38
|
384
|
10
|
$ |
93.47
|
$ |
8.48
|
$ |
57.06
|
|||||||||||||||
West
Africa (3)
(4)
|
14
|
194
|
-
|
109.90
|
0.27
|
-
|
||||||||||||||||||
North
Sea
|
12
|
6
|
-
|
117.44
|
11.54
|
-
|
||||||||||||||||||
Israel
|
-
|
155
|
-
|
-
|
3.57
|
-
|
||||||||||||||||||
Ecuador
(5)
|
-
|
21
|
-
|
-
|
-
|
-
|
||||||||||||||||||
Other
International
|
3
|
-
|
-
|
106.03
|
-
|
-
|
||||||||||||||||||
Total
Consolidated Operations
|
67
|
760
|
10
|
101.82
|
5.31
|
57.06
|
||||||||||||||||||
Equity
Investees (6)
|
2
|
-
|
5
|
116.04
|
-
|
67.56
|
||||||||||||||||||
Total
|
69
|
760
|
15
|
$ |
102.25
|
$ |
5.31
|
$ |
60.80
|
|||||||||||||||
Nine
Months Ended September 30, 2009
|
||||||||||||||||||||||||
United
States (1)
(2)
|
37
|
401
|
10
|
$ |
50.45
|
$ |
3.36
|
$ |
24.70
|
|||||||||||||||
West
Africa (3)
(4)
|
14
|
238
|
-
|
51.94
|
0.27
|
-
|
||||||||||||||||||
North
Sea
|
7
|
5
|
-
|
57.61
|
5.94
|
-
|
||||||||||||||||||
Israel
|
-
|
117
|
-
|
-
|
3.27
|
-
|
||||||||||||||||||
Ecuador
(5)
|
-
|
24
|
-
|
-
|
-
|
-
|
||||||||||||||||||
Other
International
|
4
|
-
|
-
|
49.76
|
-
|
-
|
||||||||||||||||||
Total
Consolidated Operations
|
62
|
785
|
10
|
51.55
|
2.40
|
24.70
|
||||||||||||||||||
Equity
Investees (6)
|
2
|
-
|
6
|
56.42
|
-
|
31.65
|
||||||||||||||||||
Total
|
64
|
785
|
16
|
$ |
51.70
|
$ |
2.40
|
$ |
27.40
|
|||||||||||||||
Nine
Months Ended September 30, 2008
|
||||||||||||||||||||||||
United
States (1)
(2)
|
41
|
393
|
10
|
$ |
87.84
|
$ |
9.10
|
$ |
57.39
|
|||||||||||||||
West
Africa (3)
(4)
|
15
|
212
|
-
|
103.31
|
0.27
|
-
|
||||||||||||||||||
North
Sea
|
10
|
6
|
-
|
114.42
|
10.62
|
-
|
||||||||||||||||||
Israel
|
-
|
140
|
-
|
-
|
3.15
|
-
|
||||||||||||||||||
Ecuador
(5)
|
-
|
22
|
-
|
-
|
-
|
-
|
||||||||||||||||||
Other
International
|
4
|
-
|
-
|
73.37
|
-
|
-
|
||||||||||||||||||
Total
Consolidated Operations
|
70
|
773
|
10
|
78.89
|
5.50
|
57.39
|
||||||||||||||||||
Equity
Investees (6)
|
2
|
-
|
6
|
110.43
|
-
|
66.08
|
||||||||||||||||||
Total
|
72
|
773
|
16
|
$ |
95.47
|
$ |
5.50
|
$ |
60.80
|
(1)
|
Average
realized crude oil and condensate prices reflect reductions of $1.89 per
Bbl and $22.95 per Bbl for third quarter 2009 and 2008, respectively, and
reductions of $2.28 per Bbl and $21.69 per Bbl for the first nine months
of 2009 and 2008, respectively, from hedging activities. The price
reductions resulted from hedge losses that were previously deferred in
AOCL.
|
(2)
|
Average
realized natural gas prices reflect an increase of $0.01 per Mcf and a
reduction of $0.12 per Mcf for third quarter 2009 and 2008, respectively,
and an increase of $0.29 per Mcf for the first nine months of 2008 from
hedging activities. The price increases and reduction resulted
from hedge gains and losses that were previously deferred in AOCL. The
average realized natural gas price for the first nine months of 2009 was
not impacted by hedging activities, as the net deferred gain reclassified
from AOCL was de minimis.
|
(3)
|
Average
realized crude oil and condensate prices reflect reductions of $5.32 per
Bbl and $7.42 per Bbl for third quarter 2009 and 2008, respectively, and
$5.84 per Bbl and $8.10 per Bbl for the first nine months of 2009 and
2008, respectively, from hedging activities. The price
reductions resulted from hedge losses that were previously deferred in
AOCL.
|
(4)
|
Natural
gas from the Alba field in Equatorial Guinea is under contract for $0.25
per MMBtu to a methanol plant, an LPG plant and an LNG plant. The methanol
and LPG plants are owned by affiliated entities accounted for under the
equity method of accounting. Natural gas volumes sold to the
LNG plant totaled 175 MMcfpd and 160 MMcfpd during third quarter 2009 and
2008, respectively, and 187 MMcfpd and 169 MMcfpd during the first nine
months of 2009 and 2008,
respectively.
|
(5)
|
The
natural gas-to-power project in Ecuador is 100% owned by our subsidiaries
and intercompany natural gas sales are eliminated for accounting purposes.
Electricity sales are included in other revenues. See Item 1. Financial
Statements – Note 2 – Basis of
Presentation.
|
(6)
|
Volumes
represent sales of condensate and LPG from the Alba plant in Equatorial
Guinea. See Equity
Method Investees below.
|
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(MBopd)
|
||||||||||||||||
United
States
|
39 | 38 | 37 | 41 | ||||||||||||
West
Africa
|
14 | 15 | 16 | 15 | ||||||||||||
North
Sea
|
7 | 9 | 9 | 10 | ||||||||||||
Other
International
|
4 | 3 | 5 | 4 | ||||||||||||
Total
Consolidated Operations
|
64 | 65 | 67 | 70 | ||||||||||||
Equity
Investees
|
2 | 2 | 2 | 2 | ||||||||||||
Total
|
66 | 67 | 69 | 72 |
Commodity
Price Increase (Decrease)
|
||||||||||||||||
Crude
Oil & Condensate
|
Natural
Gas
|
Crude
Oil & Condensate
|
Natural
Gas
|
|||||||||||||
2009
|
2008
|
|||||||||||||||
(Per
Bbl)
|
(Per
Mcf)
|
(Per
Bbl)
|
(Per
Mcf)
|
|||||||||||||
Three
Months Ended September 30,
|
||||||||||||||||
United
States
|
$ | 9.29 | $ | 1.95 | $ | (14.10 | ) | $ | (0.20 | ) | ||||||
West
Africa
|
12.99 | - | (9.76 | ) | - | |||||||||||
Total
Consolidated Operations
|
8.41 | 1.00 | (9.96 | ) | (0.10 | ) | ||||||||||
Total
|
8.14 | 1.00 | (9.66 | ) | (0.10 | ) | ||||||||||
Nine
Months Ended September 30,
|
||||||||||||||||
United
States
|
$ | 14.38 | $ | 1.84 | $ | (9.62 | ) | $ | (0.55 | ) | ||||||
West
Africa
|
17.48 | - | (7.71 | ) | - | |||||||||||
Total
Consolidated Operations
|
12.46 | 0.97 | (7.28 | ) | (0.29 | ) | ||||||||||
Total
|
12.09 | 0.97 | (7.09 | ) | (0.29 | ) |
|
·
|
a
38% decline in total consolidated average realized
prices;
|
|
·
|
downtime
beginning in mid-August at the Dumbarton field in the UK sector of the
North Sea due to FPSO repairs; and
|
|
·
|
natural
field decline in the deepwater Gulf of Mexico and Gulf Coast
area;
|
|
offset
by
|
|
·
|
increased
production from the Wattenberg field in the northern region of our US
operations due to ongoing development activity;
and
|
|
·
|
return
of Ticonderoga in the deepwater Gulf of Mexico to full production in
August 2009 after being off-line after Hurricane Ike in
2008.
|
|
·
|
a
35% decline in total consolidated average realized
prices;
|
|
·
|
impact
of shut-ins related to Hurricane Ike in the deepwater Gulf of
Mexico;
|
|
·
|
downtime
beginning in mid-August at the Dumbarton field in the UK sector of the
North Sea due to FPSO repairs; and
|
|
·
|
natural
field decline in the deepwater Gulf of Mexico and Gulf Coast
area;
|
|
offset
by
|
|
·
|
increased
Wattenberg field production due to ongoing development
activity.
|
|
·
|
a
55% decline in total consolidated average realized prices;
and
|
|
·
|
natural
field decline in the deepwater Gulf of Mexico, Gulf Coast and
Mid-continent areas;
|
|
offset
by
|
|
·
|
increased
production from the Wattenberg, Piceance and Shattuck (Western Oklahoma)
areas of our US operations;
|
|
·
|
return
of Ticonderoga in the deepwater Gulf of Mexico to full production;
and
|
|
·
|
sales
of natural gas from the Raton development in the deepwater Gulf of Mexico
which began year-end 2008.
|
|
·
|
a
56% decline in total consolidated average realized
prices;
|
|
·
|
shut-ins
related to Hurricane Ike in the deepwater Gulf of Mexico;
and
|
|
·
|
decreased
Israel natural gas sales due to power plant downtime and competing natural
gas sales from Egypt;
|
|
offset
by
|
|
·
|
increased
production from the Wattenberg, Piceance and Shattuck
areas;
|
|
·
|
sales
of natural gas from the Raton development in the deepwater Gulf of Mexico
which began year-end 2008; and
|
|
·
|
increase
in Equatorial Guinea volumes sold to the LNG plant due to less maintenance
downtime at the LNG plant.
|
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Net
Income (in millions):
|
||||||||||||||||
AMPCO
and Affiliates
|
$ | 6 | $ | 5 | $ | 9 | $ | 51 | ||||||||
Alba
Plant
|
19 | 35 | 43 | 107 | ||||||||||||
Dividends
(in millions):
|
||||||||||||||||
AMPCO
and Affiliates
|
6 | 16 | 6 | 54 | ||||||||||||
Alba
Plant
|
26 | 55 | 31 | 138 | ||||||||||||
Sales
Volumes:
|
||||||||||||||||
Methanol
(MMgal)
|
41 | 23 | 109 | 93 | ||||||||||||
Condensate
(MBopd)
|
2 | 2 | 2 | 2 | ||||||||||||
LPG
(MBpd)
|
6 | 5 | 6 | 6 | ||||||||||||
Production
Volumes:
|
||||||||||||||||
Methanol
(MMgal)
|
35 | 21 | 111 | 83 | ||||||||||||
Condensate
(MBopd)
|
2 | 2 | 2 | 2 | ||||||||||||
LPG
(MBpd)
|
6 | 6 | 6 | 6 | ||||||||||||
Average
Realized Prices:
|
||||||||||||||||
Methanol
(per gallon)
|
$ | 0.64 | $ | 1.16 | $ | 0.52 | $ | 1.33 | ||||||||
Condensate
(per Bbl)
|
66.33 | 116.04 | 56.42 | 110.43 | ||||||||||||
LPG
(per Bbl)
|
38.26 | 67.56 | 31.65 | 66.08 |
Total
|
United
States
|
West
Africa
|
North
Sea
|
Israel
|
Other
Int'l, Corporate(1)
|
|||||||||||||||||||
(in
millions)
|
||||||||||||||||||||||||
Three
Months Ended September 30, 2009
|
||||||||||||||||||||||||
Lease
Operating Expense (2)
|
$ | 88 | $ | 55 | $ | 13 | $ | 13 | $ | 3 | $ | 4 | ||||||||||||
Production
and Ad Valorem Taxes
|
25 | 21 | - | - | - | 4 | ||||||||||||||||||
Transportation
Expense
|
18 | 16 | - | 1 | - | 1 | ||||||||||||||||||
Total
Production Costs
|
$ | 131 | $ | 92 | $ | 13 | $ | 14 | $ | 3 | $ | 9 | ||||||||||||
Three
Months Ended September 30, 2008
|
||||||||||||||||||||||||
Lease
Operating Expense (2)
|
$ | 98 | $ | 64 | $ | 10 | $ | 18 | $ | 3 | $ | 3 | ||||||||||||
Production
and Ad Valorem Taxes
|
47 | 38 | - | - | - | 9 | ||||||||||||||||||
Transportation
Expense
|
14 | 12 | - | 2 | - | - | ||||||||||||||||||
Total
Production Costs
|
$ | 159 | $ | 114 | $ | 10 | $ | 20 | $ | 3 | $ | 12 | ||||||||||||
Nine
Months Ended September 30, 2009
|
||||||||||||||||||||||||
Lease
Operating Expense (2)
|
$ | 281 | $ | 196 | $ | 33 | $ | 32 | $ | 7 | $ | 13 | ||||||||||||
Production
and Ad Valorem Taxes
|
66 | 58 | - | - | - | 8 | ||||||||||||||||||
Transportation
Expense
|
43 | 37 | - | 3 | - | 3 | ||||||||||||||||||
Total
Production Costs
|
$ | 390 | $ | 291 | $ | 33 | $ | 35 | $ | 7 | $ | 24 | ||||||||||||
Nine
Months Ended September 30, 2008
|
||||||||||||||||||||||||
Lease
Operating Expense (2)
|
$ | 268 | $ | 183 | $ | 29 | $ | 38 | $ | 7 | $ | 11 | ||||||||||||
Production
and Ad Valorem Taxes
|
141 | 112 | - | - | - | 29 | ||||||||||||||||||
Transportation
Expense
|
43 | 36 | - | 6 | - | 1 | ||||||||||||||||||
Total
Production Costs
|
$ | 452 | $ | 331 | $ | 29 | $ | 44 | $ | 7 | $ | 41 |
|
(1)
|
Other
international includes Ecuador, China, and Argentina (through February
2008).
|
|
(2)
|
Lease
operating expense includes oil and gas operating costs (labor, fuel,
repairs, replacements, saltwater disposal and other related lifting costs)
and workover expense.
|
|
·
|
decrease
in US lease operating expense associated with cost savings initiatives
including reduced repair programs and a reduction of other discretionary
spending in our onshore US operations including a reduced workover program
in the Northern region;
|
|
·
|
decrease
in North Sea lease operating expense due to lower sales volumes, resulting
in an increase in crude oil inventory, which includes production cost
expense;
|
|
·
|
decrease
in production and ad valorem taxes due to reduced proceeds from sales
attributable to lower commodity prices in the US and China and the
cessation of production due to the sale of our interest in Argentina;
and
|
|
·
|
decrease
in North Sea transportation expense due to decrease in
production;
|
|
offset
by
|
|
·
|
increase
in West Africa lease operating expense due to higher contractor costs;
and
|
|
·
|
increase
in US transportation expense due to start up of a new interstate crude oil
transportation pipeline system used to market our Wattenberg
production.
|
|
·
|
decrease
in North Sea lease operating expense due to an increase in crude oil
inventory;
|
|
·
|
decrease
in US lease operating expense due to a reduced workover program in the
Northern region;
|
|
·
|
decrease
in production and ad valorem taxes due to reduced proceeds from sales
attributable to lower commodity prices in the US and China and the
cessation of production due to the sale of our interest in Argentina;
and
|
|
·
|
decrease
in North Sea transportation expense due to decrease in
production;
|
|
offset
by
|
|
·
|
increase
in US lease operating expense due to an increase in well count, higher
salt water disposal costs in the Northern region and higher insurance
expense;
|
|
·
|
increase
in West Africa lease operating expense due to higher contractor costs and
higher maintenance expense; and
|
|
·
|
increase
in US transportation expense due to start up of a new interstate crude oil
transportation pipeline system used to market our Wattenberg
production.
|
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Lease
Operating Expense
|
$ | 4.57 | $ | 5.22 | $ | 5.07 | $ | 4.69 | ||||||||
Production
and Ad Valorem Taxes
|
1.28 | 2.50 | 1.19 | 2.47 | ||||||||||||
Transportation
Expense
|
0.93 | 0.76 | 0.77 | 0.75 | ||||||||||||
Total
Production Costs (1)
(2)
|
$ | 6.78 | $ | 8.48 | $ | 7.03 | $ | 7.91 |
(1)
|
Consolidated
unit rates exclude sales volumes and expenses attributable to equity
method investees. Sales volumes include natural gas sales to an LNG plant
in Equatorial Guinea. The inclusion of these volumes reduced the unit rate
by $1.10 per BOE and $1.28 per BOE for third quarter 2009 and 2008,
respectively, and $1.28 per BOE and $1.23 per BOE for the first nine
months of 2009 and 2008,
respectively.
|
(2)
|
Natural
gas is converted on the basis of six Mcf of gas per one barrel of oil
equivalent.
|
Total
|
United
States
|
West
Africa
|
North
Sea
|
Eastern
Mediter-ranean
|
Other
Int'l, Corporate (1)
|
|||||||||||||||||||
(in
millions)
|
||||||||||||||||||||||||
Three
Months Ended September 30, 2009
|
||||||||||||||||||||||||
Dry
Hole Expense
|
$ | 3 | $ | 3 | $ | - | $ | - | $ | - | $ | - | ||||||||||||
Seismic
|
7 | 5 | - | - | 2 | - | ||||||||||||||||||
Staff
Expense
|
17 | 4 | 3 | - | - | 10 | ||||||||||||||||||
Other
|
- | - | - | - | - | - | ||||||||||||||||||
Total
Exploration Expense
|
$ | 27 | $ | 12 | $ | 3 | $ | - | $ | 2 | $ | 10 | ||||||||||||
Three
Months Ended September 30, 2008
|
||||||||||||||||||||||||
Dry
Hole Expense
|
$ | 10 | $ | 10 | $ | - | $ | - | $ | - | $ | - | ||||||||||||
Seismic
|
14 | 11 | - | - | 3 | - | ||||||||||||||||||
Staff
Expense
|
14 | 3 | - | - | - | 11 | ||||||||||||||||||
Other
|
1 | 1 | - | - | - | - | ||||||||||||||||||
Total
Exploration Expense
|
$ | 39 | $ | 25 | $ | - | $ | - | $ | 3 | $ | 11 | ||||||||||||
Nine
Months Ended September 30, 2009
|
||||||||||||||||||||||||
Dry
Hole Expense
|
$ | 11 | $ | 8 | $ | 4 | $ | - | $ | - | $ | (1 | ) | |||||||||||
Seismic
|
37 | 33 | - | - | 4 | - | ||||||||||||||||||
Staff
Expense
|
50 | 10 | 9 | 1 | 1 | 29 | ||||||||||||||||||
Other
|
4 | 4 | - | - | - | - | ||||||||||||||||||
Total
Exploration Expense
|
$ | 102 | $ | 55 | $ | 13 | $ | 1 | $ | 5 | $ | 28 | ||||||||||||
Nine
Months Ended September 30, 2008
|
||||||||||||||||||||||||
Dry
Hole Expense
|
$ | 78 | $ | 37 | $ | 1 | $ | 8 | $ | - | $ | 32 | ||||||||||||
Seismic
|
47 | 40 | - | 4 | 3 | - | ||||||||||||||||||
Staff
Expense
|
45 | 9 | 4 | 4 | - | 28 | ||||||||||||||||||
Other
|
11 | 11 | - | - | - | - | ||||||||||||||||||
Total
Exploration Expense
|
$ | 181 | $ | 97 | $ | 5 | $ | 16 | $ | 3 | $ | 60 |
(1)
|
Other
international includes amounts spent in support of various international
new ventures.
|
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions, except unit rate)
|
||||||||||||||||
DD&A
Expense
|
$ | 201 | $ | 191 | $ | 590 | $ | 586 | ||||||||
Accretion
of Discount on Asset Retirement Obligations
|
4 | 3 | 11 | 7 | ||||||||||||
Total
DD&A Expense
|
$ | 205 | $ | 194 | $ | 601 | $ | 593 | ||||||||
Unit
Rate per BOE
(1)
|
$ | 10.68 | $ | 10.38 | $ | 10.86 | $ | 10.37 |
(1)
|
Consolidated
unit rates exclude sales volumes and expenses attributable to equity
method investees. Sales volumes include natural gas sales to an LNG plant
in Equatorial Guinea. The inclusion of these volumes reduced the unit rate
by $1.44 per BOE and $1.25 per BOE for third quarter 2009 and 2008,
respectively, and $1.64 and $1.31 per BOE for the first nine months of
2009 and 2008, respectively.
|
|
·
|
higher
production in the Wattenberg, Piceance and Shattuck
areas;
|
|
·
|
ongoing
capital spending in the Northern region;
and
|
|
·
|
negative
reserve revisions related to lower year-end 2008 commodity
prices;
|
|
Offset
by lower sales volumes in the North
Sea.
|
|
·
|
higher
production in the Wattenberg, Piceance and Shattuck
areas;
|
|
·
|
ongoing
capital spending in the Northern
region;
|
|
·
|
negative
reserve revisions related to lower year-end 2008 commodity prices;
and
|
|
·
|
inclusion
of $4 million of abandoned asset expense in
2009.
|
|
Offset
by lower sales volumes in the North Sea and
Israel.
|
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
G&A
Expense (in millions)
|
$ | 53 | $ | 63 | $ | 173 | $ | 184 | ||||||||
Unit
Rate per BOE (1)
|
$ | 2.78 | $ | 3.37 | $ | 3.11 | $ | 3.22 |
(1)
|
Consolidated
unit rates exclude sales volumes and expenses attributable to equity
method investees. Sales volumes include natural gas sales to an LNG plant
in Equatorial Guinea. The inclusion of these volumes reduced the unit rate
by $0.47 per BOE and $0.51 per BOE for third quarter 2009 and 2008,
respectively, and $0.57 per BOE and $0.50 per BOE for the first nine
months of 2009 and 2008,
respectively.
|
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Impairment
Expense
|
$ | - | $ | 38 | $ | 437 | $ | 38 |
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Other
Operating (Income) Expense, Net
|
$ | 34 | $ | 60 | $ | 22 | $ | 107 |
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions)
|
||||||||||||||||
(Gain)
Loss on Commodity Derivative Instruments
|
$ | 28 | $ | (875 | ) | $ | 95 | $ | 190 |
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Interest
Expense
|
$ | 35 | $ | 26 | $ | 94 | $ | 75 | ||||||||
Capitalized
Interest
|
(12 | ) | (8 | ) | (30 | ) | (23 | ) | ||||||||
Interest
Expense, net
|
$ | 23 | $ | 18 | $ | 64 | $ | 52 |
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Other
Non-operating (Income) Expense, Net
|
$ | 5 | $ | (52 | ) | $ | 18 | $ | (42 | ) |
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Income
Tax Provision (Benefit) (in millions)
|
$ | 8 | $ | 480 | $ | (210 | ) | $ | 528 | |||||||
Effective
Rate
|
7 | % | 33 | % | 60 | % | 34 | % |
Nine
Months Ended
September
30,
|
||||||||
2009
|
2008
|
|||||||
(in
millions)
|
||||||||
Total
Cash Provided By (Used in):
|
||||||||
Operating
Activities
|
$ | 986 | $ | 1,867 | ||||
Investing
Activities
|
(1,012 | ) | (1,721 | ) | ||||
Financing
Activities
|
(188 | ) | 186 | |||||
Increase
(Decrease) in Cash and Cash Equivalents
|
$ | (214 | ) | $ | 332 |
Three
Months Ended
September
30,
|
Nine
Months Ended
September
30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Acquisition,
Capital and Exploration Expenditures
|
||||||||||||||||
Unproved
Property Acquisition
|
$ | 2 | $ | 36 | $ | 64 | $ | 299 | ||||||||
Proved
Property Acquisition
|
- | 255 | - | 255 | ||||||||||||
Exploration
|
22 | 142 | 167 | 385 | ||||||||||||
Development
|
186 | 334 | 615 | 840 | ||||||||||||
Corporate
and Other
|
14 | 19 | 87 | 53 | ||||||||||||
Total
|
$ | 224 | $ | 786 | $ | 933 | $ | 1,832 |
Interest
Rate Risk
|
Foreign
Currency Risk
|
|
·
|
the
extent and effect of any hedging activities engaged in by
us;
|
|
·
|
our
growth strategies;
|
|
·
|
our
ability to successfully and economically explore for and develop crude oil
and natural gas resources;
|
|
·
|
anticipated
trends in our business;
|
|
·
|
our
future results of operations;
|
|
·
|
effect
of current volatility in the credit
markets;
|
|
·
|
our
liquidity and ability to finance our exploration and development
activities;
|
|
·
|
market
conditions in the oil and gas
industry;
|
|
·
|
our
ability to make and integrate acquisitions;
and
|
|
·
|
the
impact of governmental regulation.
|
Period
|
Total
Number of Shares Purchased (1)
|
Average
Price Paid Per Share
|
Total
Number of Shares Purchased as Part of Publicly Announced Plans or
Programs
|
Approximate
Dollar Value of Shares that May Yet Be Purchased Under the Plans or
Programs
|
||||||||||||
(in
thousands)
|
||||||||||||||||
07/01/09
- 07/31/09
|
- | $ | - | - | - | |||||||||||
08/01/09
- 08/31/09
|
2,954 | 60.28 | - | - | ||||||||||||
09/01/09
- 09/30/09
|
- | - | - | - | ||||||||||||
Total
|
2,954 | $ | 60.28 | - | - |
(1)
|
Stock
repurchases during the period related to stock received by us from
employees for the payment of withholding taxes due on shares issued under
stock-based compensation plans.
|
|
NOBLE ENERGY, INC. |
|
(Registrant) |
Date
|
October
29, 2009
|
/s/
Frederick B. Bruning
|
|
Frederick
B. Bruning
Vice
President and Chief Accounting Officer
|
|||
Exhibit
Number
|
Exhibit
|
3.1
|
Certificate
of Incorporation, as amended through May 16, 2005, of the Registrant
(filed as Exhibit 3.1 to the Registrant’s Annual Report on Form 10-K for
the year ended December 31, 2008, and incorporated herein by
reference).
|
3.2
|
By-Laws
of Noble Energy, Inc. as amended through December 9, 2008 (filed as
Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date
of Event: December 9, 2008) filed December 15, 2008 and incorporated
herein by reference).
|
31.1
|
Certification
of the Company’s Chief Executive Officer Pursuant To Section 302 of the
Sarbanes-Oxley Act of 2002 (18 U.S.C. Section
7241).
|
31.2
|
Certification
of the Company’s Acting Principal Financial Officer Pursuant To Section
302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section
7241).
|
32.1
|
Certification
of the Company’s Chief Executive Officer Pursuant To Section 906 of the
Sarbanes-Oxley Act of 2002 (18 U.S.C. Section
1350).
|
32.2
|
Certification
of the Company’s Acting Principal Financial Officer Pursuant To Section
906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section
1350).
|
101
|
The
following materials from the Noble Energy, Inc. Quarterly Report on Form
10-Q for the quarter ended September 30, 2009, formatted in XBRL
(eXtensible Business Reporting Language): (i) the Consolidated
Statements of Operations, (ii) the Consolidated Balance Sheets,
(iii) the Consolidated Statements of Cash Flows, (iv) the
Consolidated Statements of Shareholders’ Equity, and (v) Notes to the
Consolidated Financial Statements, tagged as blocks of
text.
|