x
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ANNUAL REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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o
|
TRANSITION REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
Delaware
|
73-0785597
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|
(State
of incorporation)
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(I.R.S.
employer identification number)
|
|
100
Glenborough Drive, Suite 100
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||
Houston,
Texas
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77067
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|
(Address
of principal executive offices)
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(Zip
Code)
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Title
of each class
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Name
of each exchange on which registered
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|
Common
Stock, $3.33-1/3 par value
|
New
York Stock Exchange
|
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Large
accelerated filer x
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Accelerated
filer o
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Non-accelerated
filer o
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Smaller
reporting company o
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(Do
not check if a smaller reporting
company)
|
|
·
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Galapagos
(deepwater Gulf of Mexico);
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|
·
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Aseng
(offshore West Africa);
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|
·
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Tamar
(offshore Israel);
|
|
·
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Gunflint
(deepwater Gulf of Mexico);
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|
·
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Belinda
(offshore West Africa); and
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|
·
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Diega/Carmen
(offshore West Africa).
|
Summary
of Oil and Gas Reserves as of Fiscal-Year End
|
||||||||||||
Based
on Average Fiscal-Year Prices
|
||||||||||||
December
31, 2009
|
||||||||||||
Proved
Reserves
|
||||||||||||
Crude
Oil, Condensate & NGLs
|
Natural
Gas
|
Total
(1)
|
||||||||||
Reserves
Category
|
(MMBbls)
|
(Bcf)
|
(MMBoe)
|
|||||||||
Proved
Developed
|
||||||||||||
United
States
|
122 | 1,114 | 307 | |||||||||
Equatorial
Guinea
|
49 | 638 | 155 | |||||||||
Israel
|
- | 191 | 32 | |||||||||
Other
International
|
23 | 192 | 56 | |||||||||
Total
Proved Developed Reserves
|
194 | 2,135 | 550 | |||||||||
Proved
Undeveloped
|
||||||||||||
United
States
|
87 | 420 | 157 | |||||||||
Equatorial
Guinea
|
43 | 302 | 93 | |||||||||
Israel
|
- | 43 | 7 | |||||||||
Other
International
|
12 | 4 | 13 | |||||||||
Total
Proved Undeveloped Reserves
|
142 | 769 | 270 | |||||||||
Total
Proved Reserves
|
336 | 2,904 | 820 |
United
States
|
Year
Ended December 31, 2009
|
December
31, 2009
|
|||||||||||||||||||||
Sales
Volumes
|
Proved
Reserves
|
|||||||||||||||||||||
Crude
Oil & Condensate
|
Natural
Gas
|
NGLs
|
Total
|
Crude
Oil, Condensate & NGLs
|
Natural
Gas
|
Total
|
||||||||||||||||
(MBpd)
|
(MMcfpd)
|
(MBpd)
|
(MBoepd)
|
(MMBbls)
|
(Bcf)
|
(MMBoe)
|
||||||||||||||||
Northern
Region
|
||||||||||||||||||||||
Wattenberg
Field
|
15 | 150 | 6 | 46 | 129 | 819 | 266 | |||||||||||||||
Mid-continent
Area
|
7 | 66 | 1 | 19 | 34 | 279 | 80 | |||||||||||||||
Other
|
- | 95 | - | 16 | 1 | 290 | 49 | |||||||||||||||
Total
|
22 | 311 | 7 | 81 | 164 | 1,388 | 395 | |||||||||||||||
Southern
Region
|
||||||||||||||||||||||
Deepwater
Gulf of Mexico
|
10 | 49 | 3 | 21 | 26 | 47 | 34 | |||||||||||||||
Other
|
5 | 37 | - | 11 | 19 | 98 | 35 | |||||||||||||||
Total
|
15 | 86 | 3 | 32 | 45 | 145 | 69 | |||||||||||||||
Total
United States
|
37 | 397 | 10 | 113 | 209 | 1,533 | 464 |
Year
Ended December 31, 2009
|
December
31, 2009
|
||||||
Gross
Wells Drilled or Participated in
|
Gross
Productive Wells
|
||||||
Northern
Region
|
|||||||
Wattenberg
Field
|
424
|
6,285
|
|||||
Mid-Continent
Area
|
31
|
3,920
|
|||||
Other
|
145
|
2,648
|
|||||
Total
|
600
|
12,853
|
|||||
Southern
Region
|
|||||||
Deepwater
Gulf of Mexico
|
2
|
11
|
|||||
Other
|
32
|
1,180
|
|||||
Total
|
34
|
1,191
|
|||||
Total
United States
|
634
|
14,044
|
Year
Ended December 31, 2009
|
December
31, 2009
|
|||||||||||||||||||||||||||
Sales
Volumes
|
Proved
Reserves
|
|||||||||||||||||||||||||||
Crude
Oil & Condensate
|
Natural
Gas
|
NGL's
|
Total
|
Crude
Oil, Condensate & NGLs
|
Natural
Gas
|
Total
|
||||||||||||||||||||||
(MBpd)
|
(MMcfpd)
|
(MBpd)
|
(MBoepd)
|
(MMBbls)
|
(Bcf)
|
(MMBoe)
|
||||||||||||||||||||||
International
|
||||||||||||||||||||||||||||
Equatorial
Guinea
|
14 | 239 | - | 54 | 92 | 940 | 248 | |||||||||||||||||||||
Israel
|
- | 114 | - | 19 | - | 234 | 39 | |||||||||||||||||||||
Other
|
11 | 31 | - | 16 | 35 | 196 | 69 | |||||||||||||||||||||
Total
International
|
25 | 384 | - | 89 | 127 | 1,370 | 356 | |||||||||||||||||||||
Equity
Investee
|
2 | - | 6 | 8 | - | - | - | |||||||||||||||||||||
Total
|
27 | 384 | 6 | 97 | 127 | 1,370 | 356 | |||||||||||||||||||||
Equity
Investee Share of Methanol Sales (MMgal)
|
145 |
Year
Ended December 31, 2009
|
December
31, 2009
|
||||||
Gross
Wells Drilled or Participated in
|
Gross
Productive Wells
|
||||||
International
|
|||||||
Equatorial
Guinea
|
1
|
24
|
|||||
Israel
|
3
|
5
|
|||||
North
Sea
|
6
|
30
|
|||||
Ecuador
|
-
|
3
|
|||||
China
|
1
|
16
|
|||||
Total
International
|
11
|
78
|
|
·
|
Commodity
Prices – Economic
producibility of reserves and discounted cash flows are now based on a
12-month average commodity price unless contractual arrangements designate
the price to be used.
|
|
·
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Disclosure
of Unproved Reserves
– Probable and possible reserves may be disclosed separately on a
voluntary basis.
|
|
·
|
Proved
Undeveloped Reserves Guidelines – Reserves may be
classified as proved undeveloped if there is a high degree of confidence
that the quantities will be recovered and they are scheduled to be drilled
within the next five years, unless the specific circumstances justify a
longer time.
|
|
·
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Reserves
Estimation Using New Technologies – Reserves may be
estimated through the use of reliable technology in addition to flow tests
and production history.
|
|
·
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Reserves
Personnel and Estimation Process – Additional disclosure
is required regarding the qualifications of the chief technical person who
oversees the reserves estimation process. We are also 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 has expanded and focuses on
the marketable product rather than the method of
extraction.
|
|
·
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conversion
of approximately 23 MMBoe PUDs into proved developed
reserves;
|
|
·
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reclassification
of approximately 18 MMBoe PUDs that were not scheduled to be developed
within five years from proved to probable reserves;
and
|
|
·
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negative
revisions of approximately 23 MMBoe in PUDs due to changes in commodity
prices.
|
|
·
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Item
7. Management’s Discussion and Analysis of Financial Condition and Results
of Operations – Proved Reserves for a discussion of changes in proved
reserves;
|
|
·
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Item
7. Management’s Discussion and Analysis of Financial Condition and Results
of Operations – Critical Accounting Policies and Estimates – Reserves for
further discussion of our reserves estimation
process;
|
|
·
|
Item
8. Financial Statements and Supplementary Data – Supplementary Oil and Gas
Information (Unaudited) for additional information regarding estimates of
crude oil and natural gas reserves, including estimates of proved, proved
developed, and proved undeveloped reserves, the standardized measure of
discounted future net cash flows, and the changes in the standardized
measure of discounted future net cash
flows.
|
Sales
Volumes
|
Average
Sales Price
|
Production
Cost
(1)
|
||||||||||||||||||||
Crude
Oil MBpd
|
Natural
Gas MMcfpd
|
NGLs
MBpd
|
Crude
Oil Per Bbl
|
Natural
Gas Per Mcf
|
NGLs
Per Bbl
|
Per
BOE
|
||||||||||||||||
Year
Ended December 31, 2009
|
||||||||||||||||||||||
United
States
|
||||||||||||||||||||||
Wattenberg
Field
|
15 | 150 | 6 | $ | 55.57 | $ | 3.59 | $ | 29.10 | $ | 3.01 | |||||||||||
Other
US
|
22 | 247 | 4 | 54.92 | 3.62 | 26.37 | 8.50 | |||||||||||||||
Total
US (2)
|
37 | 397 | 10 | 55.19 | 3.61 | 27.96 | 6.26 | |||||||||||||||
Alba
Field (Equatorial Guinea) (3)
|
14 | 239 | - | 55.94 | 0.27 | - | 2.30 | |||||||||||||||
Israel
|
- | 114 | - | - | 3.47 | - | 1.36 | |||||||||||||||
North
Sea
|
7 | 5 | - | 59.51 | 5.75 | - | 15.81 | |||||||||||||||
Ecuador
|
- | 26 | - | - | - | - | - | |||||||||||||||
China
|
4 | - | - | 54.40 | - | - | 6.75 | |||||||||||||||
Total
Consolidated Operations
|
62 | 781 | 10 | 55.76 | 2.54 | 27.96 | $ | 5.05 | ||||||||||||||
Equity
Investee (4)
|
2 | - | 6 | 59.51 | - | 36.03 | ||||||||||||||||
Total
|
64 | 781 | 16 | $ | 55.87 | $ | 2.54 | $ | 31.20 | |||||||||||||
Year
Ended December 31, 2008
|
||||||||||||||||||||||
United
States
|
||||||||||||||||||||||
Wattenberg
Field
|
15 | 146 | 5 | $ | 71.41 | $ | 7.39 | $ | 52.19 | $ | 3.12 | |||||||||||
Other
US
|
25 | 249 | 4 | 78.02 | 8.55 | $ | 47.51 | 7.91 | ||||||||||||||
Total
US (2)
|
40 | 395 | 9 | 75.53 | 8.12 | $ | 50.15 | 6.08 | ||||||||||||||
Alba
Field (Equatorial Guinea) (3)
|
15 | 206 | - | 88.95 | 0.27 | - | 2.17 | |||||||||||||||
Israel
|
- | 139 | - | - | 3.10 | - | 1.07 | |||||||||||||||
North
Sea
|
10 | 5 | - | 100.56 | 10.54 | - | 12.63 | |||||||||||||||
Ecuador
|
- | 22 | - | - | - | - | - | |||||||||||||||
China
|
4 | - | - | 82.66 | - | - | 7.03 | |||||||||||||||
Total
Consolidated Operations
|
69 | 767 | 9 | 82.60 | 5.04 | 50.15 | $ | 4.90 | ||||||||||||||
Equity
Investee (4)
|
2 | - | 6 | 96.77 | - | 58.81 | ||||||||||||||||
Total
|
71 | 767 | 15 | $ | 82.96 | $ | 5.04 | $ | 53.45 | |||||||||||||
Year
Ended December 31, 2007
|
||||||||||||||||||||||
United
States
|
||||||||||||||||||||||
Wattenberg
Field
|
13 | 163 | - | $ | 68.19 | $ | 5.52 | $ | - | $ | 2.68 | |||||||||||
Other
US
|
29 | 249 | - | 46.76 | 8.82 | - | 6.72 | |||||||||||||||
Total
US (2)
|
42 | 412 | - | 53.22 | 7.51 | - | 5.26 | |||||||||||||||
Alba
Field (Equatorial Guinea) (3)
|
15 | 132 | - | 71.27 | 0.29 | - | 2.89 | |||||||||||||||
Israel
|
- | 111 | - | - | 2.79 | - | 1.14 | |||||||||||||||
North
Sea
|
13 | 6 | - | 76.47 | 6.54 | - | 7.68 | |||||||||||||||
Ecuador
|
- | 26 | - | - | - | - | - | |||||||||||||||
China
|
4 | 58.79 | 7.08 | |||||||||||||||||||
Argentina
(5)
|
3 | - | - | 46.79 | - | - | 11.79 | |||||||||||||||
Total
Consolidated Operations
|
77 | 687 | - | 60.61 | 5.26 | - | $ | 4.62 | ||||||||||||||
Equity
Investee (4)
|
2 | - | 6 | 74.87 | - | 48.87 | ||||||||||||||||
Total
|
79 | 687 | 6 | $ | 60.94 | $ | 5.26 | $ | 48.87 |
(1)
|
Average
production cost includes oil and gas operating costs and workover and
repair expense and excludes production and ad valorem
taxes.
|
(2)
|
Average
crude oil sales prices reflect reductions of $2.13 per Bbl (2009), $22.06
per Bbl (2008), and $13.68 per Bbl (2007) from hedging activities. Average
natural gas sales prices reflect increases of $0.23 per Mcf (2008), and
$1.12 per Mcf (2007) from hedging activities. The effect of hedging
activities on the average realized natural gas price for 2009 was de
minimis.
|
(3)
|
Average
crude oil sales prices reflect reductions of $5.57 per Bbl (2009), $7.59
per Bbl (2008), and $2.19 per Bbl (2007) from hedging activities.
Natural gas is under contract for $0.25 per MMBtu to a methanol
plant, an LPG plant and an LNG plant. Sales to these plants are based on a
BTU equivalent and then converted to a dry gas equivalent volume. The
methanol and LPG plants are owned by affiliated entities accounted for
under the equity method of accounting. The volumes produced by the LPG
plant are included in the crude oil
information.
|
(4)
|
Volumes
represent sales of condensate and LPG from the LPG plant in Equatorial
Guinea.
|
(5)
|
We
sold our Argentina assets in February
2008.
|
Crude
Oil Wells
|
Natural
Gas Wells
|
Total
|
|||||||||||||||||||
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
||||||||||||||||
United
States
|
|||||||||||||||||||||
Northern
Region
|
7,825 | 6,119.0 | 5,028 | 3,637.9 | 12,853 | 9,756.9 | |||||||||||||||
Southern
Region
|
799 | 593.0 | 392 | 175.0 | 1,191 | 768.0 | |||||||||||||||
Equatorial
Guinea
|
4 | 1.7 | 20 | 7.7 | 24 | 9.4 | |||||||||||||||
Israel
|
- | - | 5 | 2.4 | 5 | 2.4 | |||||||||||||||
North
Sea
|
22 | 4.7 | 8 | 1.0 | 30 | 5.7 | |||||||||||||||
Ecuador
|
- | - | 3 | 3.0 | 3 | 3.0 | |||||||||||||||
China
|
15 | 8.6 | 1 | 0.6 | 16 | 9.2 | |||||||||||||||
Total
|
8,665 | 6,727.0 | 5,457 | 3,827.6 | 14,122 | 10,554.6 |
Developed
Acreage
|
Undeveloped
Acreage
|
||||||||||||
Gross
|
Net
|
Gross
|
Net
|
||||||||||
(thousands)
|
|||||||||||||
United
States
|
|||||||||||||
Onshore
|
1,625 | 956 | 1,603 | 1,262 | |||||||||
Offshore
|
134 | 84 | 524 | 362 | |||||||||
Total
United States
|
1,759 | 1,040 | 2,127 | 1,624 | |||||||||
International
|
|||||||||||||
Equatorial
Guinea
|
140 | 53 | 523 | 212 | |||||||||
Cameroon
|
- | - | 1,125 | 563 | |||||||||
Israel
|
62 | 29 | 1,790 | 796 | |||||||||
North
Sea (1)
|
50 | 6 | 229 | 44 | |||||||||
Ecuador
|
12 | 12 | 849 | 849 | |||||||||
China
|
7 | 4 | - | - | |||||||||
Suriname
|
- | - | 3,087 | 1,389 | |||||||||
Nicaragua
|
- | - | 1,977 | 1,977 | |||||||||
Cyprus
|
- | - | 1,136 | 795 | |||||||||
India
|
- | - | 694 | 347 | |||||||||
Total
International
|
271 | 104 | 11,410 | 6,972 | |||||||||
Total
(2)
|
2,030 | 1,144 | 13,537 | 8,596 |
(1)
|
The
North Sea includes acreage in the UK and the
Netherlands.
|
(2)
|
Approximately
687,000 gross acres (407,000 net acres) will expire in 2010; 1.4 million
gross acres (975,000 net acres) will expire in 2011; and 172,000 gross
acres (121,000 net acres) will expire in 2012 if production is not
established or we take no other action to extend the terms of the leases
or concessions.
|
Net
Exploratory Wells
|
Net
Development Wells
|
|||||||||||||||||||||
Productive
|
Dry
|
Total
|
Productive
|
Dry
|
Total
|
Total
|
||||||||||||||||
Year
Ended December 31, 2009
|
||||||||||||||||||||||
United
States
|
||||||||||||||||||||||
Northern
Region
|
2.5 | 1.0 | 3.5 | 516.9 | 1.0 | 517.9 | 521.4 | |||||||||||||||
Southern
Region
|
1.6 | 0.6 | 2.2 | 15.4 | 1.0 | 16.4 | 18.6 | |||||||||||||||
Equatorial
Guinea (1)
|
0.5 | - | 0.5 | - | - | - | 0.5 | |||||||||||||||
Israel
(1)
|
1.1 | - | 1.1 | - | - | - | 1.1 | |||||||||||||||
North
Sea
|
- | - | - | 1.0 | - | 1.0 | 1.0 | |||||||||||||||
China
|
- | - | - | 0.6 | - | 0.6 | 0.6 | |||||||||||||||
Total
|
5.7 | 1.6 | 7.3 | 533.9 | 2.0 | 535.9 | 543.2 | |||||||||||||||
Year
Ended December 31, 2008
|
||||||||||||||||||||||
United
States
|
||||||||||||||||||||||
Northern
Region
|
1.0 | - | 1.0 | 837.2 | 42.0 | 879.2 | 880.2 | |||||||||||||||
Southern
Region
|
14.6 | 2.0 | 16.6 | 30.9 | 2.0 | 32.9 | 49.5 | |||||||||||||||
Equatorial
Guinea (1)
|
1.3 | - | 1.3 | - | - | - | 1.3 | |||||||||||||||
North
Sea
|
- | 0.4 | 0.4 | 0.6 | 0.3 | 0.9 | 1.3 | |||||||||||||||
Suriname
|
- | 0.5 | 0.5 | - | - | - | 0.5 | |||||||||||||||
Total
|
16.9 | 2.9 | 19.8 | 868.7 | 44.3 | 913.0 | 932.8 | |||||||||||||||
Year
Ended December 31, 2007
|
||||||||||||||||||||||
United
States
|
||||||||||||||||||||||
Northern
Region
|
13.9 | 1.9 | 15.8 | 738.0 | 24.5 | 762.5 | 778.3 | |||||||||||||||
Southern
Region
|
0.3 | 2.6 | 2.9 | 19.6 | 3.1 | 22.7 | 25.6 | |||||||||||||||
Equatorial
Guinea (1)
|
2.1 | 0.5 | 2.6 | - | - | - | 2.6 | |||||||||||||||
Cameroon
(1)
|
0.5 | - | 0.5 | - | - | - | 0.5 | |||||||||||||||
Israel
|
- | - | - | 0.4 | - | 0.4 | 0.4 | |||||||||||||||
North
Sea
|
0.5 | - | 0.5 | - | - | - | 0.5 | |||||||||||||||
Argentina
(2)
|
- | 0.1 | 0.1 | 6.7 | - | 6.7 | 6.8 | |||||||||||||||
Total
|
17.3 | 5.1 | 22.4 | 764.7 | 27.6 | 792.3 | 814.7 |
(1)
|
Includes
successful exploratory wells drilled but not yet
producing.
|
(2)
|
We
sold our assets in Argentina in February
2008.
|
|
·
|
the
Bureau of Land Management (BLM) and the Minerals Management Service (MMS),
which under laws such as the Federal Land Policy and Management Act,
Endangered Species Act, National Environmental Policy Act and Outer
Continental Shelf Lands Act have certain authority over our operations on
federal lands, particularly in the Rocky Mountains and deepwater Gulf of
Mexico;
|
|
·
|
the
US Environmental Protection Agency (EPA) and the Occupational Safety and
Health Administration, which under laws such as the Comprehensive
Environmental Response, Compensation and Liability Act, as amended, the
Resource Conservation and Recovery Act, as amended, the Oil Pollution Act
of 1990, the Clean Air Act, the Clean Water Act, the Occupational Safety
and Health Act and the recent Final Mandatory Reporting of Greenhouse
Gases Rule have certain authority over environmental, health and safety
matters affecting our operations as discussed
below;
|
|
·
|
the
Federal Energy Regulatory Commission, which under laws such as the Energy
Policy Act of 2005 has certain authority over the marketing and
transportation of crude oil and natural gas we produce onshore and from
the deepwater Gulf of Mexico;
|
|
·
|
the
Department of Transportation, which has certain authority over the
transportation of products, equipment and personnel necessary to our US
onshore and deepwater Gulf of Mexico operations;
and
|
|
·
|
other
federal agencies with certain authority over our business, such as the
Internal Revenue Service and the SEC, as well as the NYSE upon which
shares of our common stock are
traded.
|
|
·
|
worldwide
and domestic supplies of crude oil and natural
gas;
|
|
·
|
actions
taken by foreign oil and gas producing
nations;
|
|
·
|
political
conditions and events (including instability or armed conflict) in crude
oil or natural gas producing
regions;
|
|
·
|
the
level of global crude oil and natural gas
inventories;
|
|
·
|
the
price and level of imported foreign crude oil and natural
gas;
|
|
·
|
the
price and availability of alternative fuels, including coal and
biofuels;
|
|
·
|
the
availability of pipeline capacity and
infrastructure;
|
|
·
|
the
availability of crude oil transportation and refining
capacity;
|
|
·
|
weather
conditions;
|
|
·
|
electricity
generation;
|
|
·
|
domestic
and foreign governmental regulations and taxes;
and
|
|
·
|
the
overall economic environment.
|
|
·
|
limiting
our financial condition, liquidity, and/or ability to finance planned
capital expenditures and
operations;
|
|
·
|
reducing
the amount of crude oil and natural gas that we can produce
economically;
|
|
·
|
causing
us to delay or postpone some of our capital
projects;
|
|
·
|
reducing
our revenues, operating income and cash flows;
or
|
|
·
|
limiting
our access to sources of capital, such as equity and long-term
debt.
|
|
·
|
a
reduction in the carrying value of our crude oil and natural gas
properties; or
|
|
·
|
a
reduction in the carrying value of
goodwill.
|
|
·
|
a
portion of our cash flows from operating activities must be used to
service our indebtedness and is not available for other
purposes;
|
|
·
|
we
may be at a competitive disadvantage as compared to similar companies that
have less debt;
|
|
·
|
the
covenants contained in the agreements governing our outstanding
indebtedness and future indebtedness may limit our ability to borrow
additional funds, pay dividends and make certain investments and may also
affect our flexibility in planning for, and reacting to, changes in the
economy and in our industry;
|
|
·
|
additional
financing in the future for working capital, capital expenditures,
acquisitions, general corporate or other purposes may have higher costs
and more restrictive covenants;
|
|
·
|
additional
financing in the future is likely to have higher costs due to the negative
impact of the credit market crisis which restricted access to the bond
markets;
|
|
·
|
changes
in the credit ratings of our debt may negatively affect the cost, terms,
conditions and availability of future financing, and lower ratings will
increase the interest rate and fees we pay on our revolving credit
facility; and
|
|
·
|
we
may be more vulnerable to general adverse economic and industry
conditions.
|
|
·
|
historical
production from the area compared with production from other
areas;
|
|
·
|
the
assumed effects of regulations by governmental agencies, including the
impact of the SEC’s new oil and gas company reserves reporting
requirements;
|
|
·
|
assumptions
concerning future crude oil and natural gas
prices;
|
|
·
|
future
operating costs;
|
|
·
|
severance
and excise taxes;
|
|
·
|
development
costs; and
|
|
·
|
workover
and remedial costs.
|
|
·
|
pipeline
ruptures and spills;
|
|
·
|
fires;
|
|
·
|
explosions,
blowouts and cratering;
|
|
·
|
formations
with abnormal pressures;
|
|
·
|
equipment
malfunctions;
|
|
·
|
hurricanes,
such as Gustav and Ike in 2008, which could affect our operations in areas
such as the Gulf Coast and deepwater Gulf of Mexico, and cyclones, which
could affect our operations offshore China;
and
|
|
·
|
other
natural disasters.
|
|
·
|
unexpected
drilling conditions;
|
|
·
|
title
problems;
|
|
·
|
pressure
or other irregularities in
formations;
|
|
·
|
equipment
failures or accidents;
|
|
·
|
adverse
weather conditions;
|
|
·
|
compliance
with environmental and other governmental requirements;
and
|
|
·
|
increases
in the cost of, or shortages or delays in the availability of, drilling
rigs and equipment.
|
|
·
|
seeking
to acquire desirable producing properties or new leases for future
exploration;
|
|
·
|
marketing
our crude oil and natural gas
production;
|
|
·
|
seeking
to acquire the equipment and expertise necessary to operate and develop
properties; and
|
|
·
|
attracting
and retaining employees with certain
skills.
|
|
·
|
war,
terrorist acts, civil disturbances, or territorial disputes, such as may
occur in regions that encompass our operations, including Ecuador, Israel
and West Africa;
|
|
·
|
loss
of revenue, property and equipment as a result of actions taken by foreign
crude oil and natural gas producing nations, such as expropriation or
nationalization of assets and renegotiation, modification or nullification
of existing contracts, such as may occur pursuant to the hydrocarbons law
enacted in 2006 by the government of Equatorial
Guinea;
|
|
·
|
changes
in taxation policies, such as the UK Finance Act of 2006, which increased
the income tax rate on our UK operations effective January 1, 2006, and
the China Petroleum Special Profits Tax enacted in 2006, which imposed an
excise tax on crude oil produced in the
country;
|
|
·
|
laws
and policies of the US and foreign jurisdictions affecting foreign
investment, taxation, trade and business
conduct;
|
|
·
|
foreign
exchange restrictions;
|
|
·
|
international
monetary fluctuations and changes in the relative value of the US dollar
as compared with the currencies of other countries in which we conduct
business, such as the UK; and
|
|
·
|
other
hazards arising out of foreign governmental sovereignty over areas in
which we conduct operations.
|
|
·
|
delay
or denial of drilling permits;
|
|
·
|
shortening
of lease terms or reduction in lease
size;
|
|
·
|
restrictions
on installation or operation of gathering or processing
facilities;
|
|
·
|
damaging
publicity about us;
|
|
·
|
increased
costs of doing business;
|
|
·
|
reduction
in demand for our products; and
|
|
·
|
other
adverse affects on our ability to develop our properties and expand
production
|
|
·
|
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, development, and
acquisition activities;
|
|
·
|
market
conditions in the oil and gas
industry;
|
|
·
|
our
ability to make and integrate acquisitions;
and
|
|
·
|
the
impact of governmental regulation.
|
Name
|
Age
|
Position
|
||
Charles
D. Davidson (1)
|
59
|
Chairman
of the Board, Chief Executive Officer and Director
|
||
David
L. Stover (2)
|
52
|
President,
Chief Operating Officer
|
||
Kenneth
M. Fisher (3)
|
48
|
Senior
Vice President, Chief Financial Officer
|
||
Ted
D. Brown (4)
|
54
|
Senior
Vice President, Northern Region
|
||
Rodney
D. Cook (5)
|
52
|
Senior
Vice President, International
|
||
Susan
M. Cunningham (6)
|
54
|
Senior
Vice President, Exploration
|
||
Arnold
J. Johnson
(7)
|
54
|
Senior
Vice President, General Counsel and Secretary
|
||
Andrea
Lee Robison
(8)
|
51
|
Vice
President, Human Resources
|
(1)
|
Charles
D. Davidson was elected Chief Executive Officer of Noble
Energy in October 2000 and Chairman of the Board in April 2001,
also serving as President until April 2009 (at which time Mr. Stover
assumed that position). Prior to October 2000, he served as
President and Chief Executive Officer of Vastar Resources, Inc. from
March 1997 to September 2000 (Chairman from April 2000) and
was a Vastar Director from March 1994 to September 2000. From
September 1993 to March 1997, he served as a Senior Vice
President of Vastar. From 1972 to October 1993, he held various
positions with ARCO.
|
(2)
|
David
L. Stover was elected President and Chief Operating Officer of Noble
Energy in April 2009. Prior thereto, he served as Executive Vice President
and Chief Operating Officer of Noble Energy from August 2006 to April
2009. He served as Senior Vice President of North America and Business
Development from July 2004 through July 2006, and he served as
Noble Energy’s Vice President of Business Development from
December 2002 through June 2004. Previous to his employment with
Noble Energy, he was employed by BP America, Inc. as Vice President,
Gulf of Mexico Shelf from September 2000 to August 2002. Prior
to joining BP, Mr. Stover was employed by Vastar, as Area Manager for
Gulf of Mexico Shelf from April 1999 to September 2000, and
prior thereto, as Area Manager for Oklahoma/Arklatex from
January 1994 to April 1999. From 1979 to 1994, he held various
positions with ARCO.
|
(3)
|
Kenneth M. Fisher
was elected a Senior Vice President and Chief Financial Officer of Noble
Energy in November 2009. Prior to joining Noble Energy, Mr. Fisher served
as Executive Vice President of Finance for Upstream Americas
for Shell from July 2009 to November 2009. Prior to his most recent
position with Shell, Mr. Fisher served as Director of Strategy &
Business Development for Royal Dutch Shell plc in The Hague from August
2007 to July 2009. He served as Executive Vice President of
Strategy & Portfolio for Shell’s downstream business in London from
January 2005 to August 2007 and was responsible for leading global
strategy, portfolio, fuels development and biofuels activity along with
central health, safety and environment functions. Mr. Fisher joined Shell
in August 2002 and served as Chief Financial Officer for Shell Oil
Products U.S. until December 2004. As Chief Financial Officer for Shell
Oil Products U.S., he was responsible for U.S. oil products finance,
information technology and contracting and procurement activities.
Prior to joining Shell, he held positions of increasing responsibility
with General Electric (GE) from 1984 to 2002,
including Vice President and Chief Financial Officer of the
Aircraft Engines Services division and a Singapore-based position as
Director of Finance & Business Development of GE’s Asia Pacific
plastics business.
|
(4)
|
Ted
D. Brown was elected a Senior Vice President of Noble Energy in April 2008
and is currently responsible for the Northern Region of our North America
division. He served as Vice President, responsible for the same region,
from August 2006 to April 2008 and as a vice president of that division
since joining us upon our acquisition of Patina in May 2005. He served as
Senior Vice President of Patina from July 2004 to May 2005. Prior thereto
he served as Director, Piceance Basin Asset along with Engineering Manager
for Williams and Barrett Resources since 1993 and, before that, in various
positions with Union Pacific Resources and Amoco Production
Company.
|
(5)
|
Rodney
D. Cook was elected a Senior Vice President of Noble Energy in April 2008
and is currently responsible for the International division. He served as
Vice President of Noble Energy, responsible for the Southern Region of our
North America division, from August 2006 to April 2008 and as a vice
president of that division from May 2005 to August 2006. He served as
Manager of our West Africa and Middle East Business Unit from 2002 to
2005. Prior thereto he served as Operations Manager of the International
division since 1996. From 1980 to 1996 he held various positions with
Noble Energy. Prior to joining Noble Energy in 1980, Mr. Cook held various
positions with Texas Pacific Oil.
|
(6)
|
Susan
M. Cunningham was elected a Senior Vice President of Noble Energy in
April 2001 and is currently responsible for our world-wide
exploration. Prior to joining Noble Energy, Ms. Cunningham was
Texaco’s Vice President of worldwide exploration from April 2000 to
March 2001. From 1997 through 1999, she was employed by
Statoil, beginning in 1997 as Exploration Manager for deepwater Gulf of
Mexico, appointed a Vice President in 1998 and responsible, in 1999, for
Statoil’s West Africa exploration efforts. She joined Amoco Canada in 1980
as a geologist and held various exploration and development positions with
Amoco Production Company until
1997.
|
(7)
|
Arnold
J. Johnson was elected Senior Vice President, General Counsel and
Secretary of Noble Energy in July 2008. Prior thereto, he served as Vice
President, General Counsel and Secretary of Noble Energy since February
2004. He served as Associate General Counsel and Assistant Secretary of
Noble Energy from January 2001 through January 2004. Previous to
his employment with Noble Energy, he served as Senior Counsel for BP
America, Inc. from October 2000 to January 2001.
Mr. Johnson held several positions as an attorney for Vastar and ARCO
from March 1989 through September 2000, most recently as
Assistant General Counsel and Assistant Secretary of Vastar from 1997
through 2000. From 1980 to March 1989, he held various positions with
ARCO.
|
(8)
|
Andrea
Lee Robison was elected to the position of Vice President of Noble Energy
in November 2007 and is responsible for Human Resources. Prior thereto,
she served as Director of Human Resources from May 2002 through October
2007. Prior to joining us, Ms. Robison was Manager of Human Resources for
the Gulf of Mexico Shelf for BP America, Inc. from September 2000 through
April 2002. Prior to her employment at BP, she served as HR Director at
Vastar from 1997 through September 2000, and Compensation Consultant from
January 1994 through 1996. From 1980 through 1993 she held various
positions with ARCO.
|
High
|
Low
|
Dividends
Per Share
|
||||||||||
2008
|
||||||||||||
First
Quarter
|
$ | 81.35 | $ | 69.18 | $ | 0.12 | ||||||
Second
Quarter
|
103.83 | 75.79 | 0.18 | |||||||||
Third
Quarter
|
102.79 | 51.18 | 0.18 | |||||||||
Fourth
Quarter
|
54.01 | 33.15 | 0.18 | |||||||||
2009
|
||||||||||||
First
Quarter
|
$ | 58.24 | $ | 40.33 | $ | 0.18 | ||||||
Second
Quarter
|
69.07 | 50.86 | 0.18 | |||||||||
Third
Quarter
|
70.35 | 51.49 | 0.18 | |||||||||
Fourth
Quarter
|
74.09 | 62.25 | 0.18 |
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)
|
|||||||||||||
10/01/09
- 10/31/09
|
- | $ | - | - | - | ||||||||
11/01/09
- 11/30/09
|
320 | 66.72 | - | - | |||||||||
12/01/09
- 12/31/09
|
- | - | - | - | |||||||||
Total
|
320 | $ | 66.72 | - | - |
(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.
|
Plan
Category
|
Number
of Securities to be Issued Upon Exercies of Outstanding Options, Warrants
and Rights
|
Weighted
Average Exercise Price of Outstanding Options, Warrants and
Rights
|
Number
of Securities Remaining Available for Future Issuance Under Equity
Compensation Plans (Excluding Securities Reflected in Column
(a))
|
|||||
(a)
|
(b)
|
(c)
|
||||||
Equity
Compensation Plans Approved by Security Holders
|
6,820,291
|
$ |
45.01
|
5,274,898
|
||||
Equity
Compensation Plans Not Approved by Security Holders
|
-
|
-
|
-
|
|||||
Total
|
6,820,291
|
$ |
45.01
|
5,274,898
|
Anadarko Petroleum Corp. | Murphy Oil Corp. |
Apache
Corp.
|
Newfield
Exploration Company
|
Cabot
Oil & Gas Corp.
|
Pioneer
Natural Resources Company
|
Chesapeake
Energy Corp.
|
Plains
Exploration and Production Company
|
Devon
Energy Corp.
|
Range
Resources Corp.
|
EOG
Resources, Inc.
|
Southwestern
Energy Company
|
Forest
Oil Corp.
|
XTO
Energy Inc.
|
Year
Ended December 31,
|
2004
|
2005
|
2006
|
2007
|
2008
|
2009
|
|||||||||||||
Noble
Energy, Inc.
|
$ | 100.00 | $ | 131.24 | $ | 160.73 | $ | 262.26 | $ | 163.94 | $ | 240.11 | |||||||
S&P
500
|
100.00 | 104.91 | 121.48 | 128.16 | 80.74 | 102.11 | |||||||||||||
Peer
Group
|
100.00 | 156.47 | 155.59 | 226.10 | 141.02 | 200.93 |
Year
Ended December 31,
|
||||||||||||||||
2009
|
2008
|
2007
|
2006
(1)
|
2005
(2)
|
||||||||||||
(millions,
except as noted)
|
||||||||||||||||
Revenues
and Income (Loss)
|
||||||||||||||||
Total
Revenues
|
$ | 2,313 | $ | 3,901 | $ | 3,272 | $ | 2,940 | $ | 2,187 | ||||||
Net
Income (Loss)
|
(131 | ) | 1,350 | 944 | 678 | 646 | ||||||||||
Per
Share Data
|
||||||||||||||||
Earnings
(Loss) Per Share
|
||||||||||||||||
Basic
|
$ | (0.75 | ) | $ | 7.83 | $ | 5.52 | $ | 3.86 | $ | 4.20 | |||||
Diluted
|
(0.75 | ) | 7.58 | 5.45 | 3.79 | 4.12 | ||||||||||
Cash
Dividends Per Share
|
0.720 | 0.660 | 0.435 | 0.275 | 0.150 | |||||||||||
Year-End
Stock Price Per Share
|
71.22 | 49.22 | 80.66 | 49.07 | 40.30 | |||||||||||
Weighted
Average Shares Outstanding
|
||||||||||||||||
Basic
|
173 | 173 | 171 | 176 | 154 | |||||||||||
Diluted
|
173 | 176 | 173 | 179 | 157 | |||||||||||
Cash
Flows
|
||||||||||||||||
Net
Cash Provided by Operating Activities
|
$ | 1,508 | $ | 2,285 | $ | 2,017 | $ | 1,730 | $ | 1,240 | ||||||
Additions
to Property, Plant and Equipment
|
1,268 | 1,971 | 1,414 | 1,357 | 786 | |||||||||||
Acquisitions
|
- | 292 | - | 412 | 1,111 | |||||||||||
Financial
Position
|
||||||||||||||||
Cash
and Cash Equivalents
|
1,014 | 1,140 | 660 | 153 | 110 | |||||||||||
Commodity
Derivative Instruments - Current
|
13 | 437 | 15 | 35 | 29 | |||||||||||
Property,
Plant, and Equipment, Net
|
8,916 | 9,004 | 7,945 | 7,171 | 6,199 | |||||||||||
Goodwill
|
758 | 759 | 761 | 781 | 863 | |||||||||||
Total
Assets
|
11,807 | 12,384 | 10,831 | 9,589 | 8,878 | |||||||||||
Long-term
Obligations
|
||||||||||||||||
Long-Term
Debt
|
2,037 | 2,241 | 1,851 | 1,801 | 2,031 | |||||||||||
Deferred
Income Taxes
|
2,076 | 2,174 | 1,984 | 1,758 | 1,201 | |||||||||||
Commodity
Derivative Instruments
|
17 | 2 | 83 | 329 | 758 | |||||||||||
Asset
Retirement Obligations
|
181 | 184 | 131 | 128 | 279 | |||||||||||
Other
|
349 | 300 | 337 | 275 | 280 | |||||||||||
Shareholders'
Equity
|
6,157 | 6,309 | 4,809 | 4,114 | 3,090 | |||||||||||
Operations
Information
|
||||||||||||||||
Consolidated
Crude Oil Sales (MBopd)
|
62 | 69 | 77 | 75 | 57 | |||||||||||
Average
Realized Price ($/Bbl) (3)
|
$ | 55.76 | $ | 82.60 | $ | 60.61 | $ | 54.47 | $ | 45.35 | ||||||
Consolidated
Natural Gas Sales (MMcfpd)
|
781 | 767 | 687 | 623 | 508 | |||||||||||
Average
Realized Price ($/Mcf) (3)
|
$ | 2.54 | $ | 5.04 | $ | 5.26 | $ | 5.55 | $ | 5.78 | ||||||
Consolidated
NGL Sales (MBpd) (4)
|
10 | 9 | - | - | - | |||||||||||
Average
Realized Price ($/Bbl)
|
$ | 27.96 | $ | 50.15 | $ | - | $ | - | $ | - | ||||||
Proved
Reserves
|
||||||||||||||||
Crude
Oil, Condensate and NGL Reserves (MMBbls)
|
336 | 311 | 329 | 296 | 291 | |||||||||||
Natural
Gas Reserves (Bcf)
|
2,904 | 3,315 | 3,307 | 3,231 | 3,091 | |||||||||||
Total
Reserves (MMBoe)
|
820 | 864 | 880 | 835 | 806 | |||||||||||
Number
of Employees
|
1,630 | 1,571 | 1,398 | 1,243 | 1,171 |
(1)
|
Includes
effect of acquisition of U.S. Exploration and sale of Gulf of Mexico shelf
properties.
|
(2)
|
Includes
effect of Patina Merger.
|
(3)
|
Prices
include effects of oil and gas hedging activities. See Item 8. Financial
Statements and Supplementary Data – Note 6. Derivative
Instruments and Hedging Activities.
|
(4)
|
Prior
to 2008, US NGL sales volumes were included with natural gas volumes.
Effective in 2008 we began reporting US NGLs separately where we have the
right to take title, which lowered the comparative natural gas sales
volumes for 2008.
|
|
·
|
net
loss of $131 million as compared with net income of $1.4 billion for
2008;
|
|
·
|
asset
impairment charges of $604 million as compared with $294 million for
2008;
|
|
·
|
$110
million loss on commodity derivative instruments (including unrealized
mark-to-market loss of $606 million) as compared with a $440 million gain
on commodity derivative instruments (including unrealized mark-to-market
gain of $522 million) for 2008;
|
|
·
|
diluted
loss per share of $0.75, as compared with diluted earnings per share of
$7.58 for 2008;
|
|
·
|
cash
flows provided by operating activities of $1.5 billion, as compared with
$2.3 billion in 2008;
|
|
·
|
capital
spending of $1.3 billion as compared with $2 billion in
2008;
|
|
·
|
issuance
of $1 billion in 10-year unsecured
notes;
|
|
·
|
reduction
of $225 million principal amount of
debt;
|
|
·
|
repatriation
of $180 million of earnings from foreign
subsidiaries;
|
|
·
|
revenues
of $86 million related to deepwater Gulf of Mexico royalties refund and
$11 million of associated interest
income;
|
|
·
|
year-end
cash balance of $1 billion, as compared with $1.1 billion at the end of
2008;
|
|
·
|
total
liquidity of $2.7 billion at December 31, 2009, consisting of year-end
cash balance plus funds available under credit facility;
and
|
|
·
|
year-end
ratio of debt-to-book capital of 25% as compared with 26% at December 31,
2008.
|
|
·
|
discovery
at Santa Cruz and sanction of the Galapagos oil
development;
|
|
·
|
successful
new completion at the Swordfish field in the deepwater Gulf of
Mexico;
|
|
·
|
spud
Deep Blue and Double Mountain exploration test wells in the deepwater Gulf
of Mexico;
|
|
·
|
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
|
|
·
|
award
of 22 lease blocks from the Central Gulf of Mexico Lease Sale
208.
|
|
·
|
announced
DJ Basin asset acquisition which will expand our largest onshore US
property at Wattenberg;
|
|
·
|
record
Wattenberg field production of 269 MMcfepd, including liquid production of
over 20 MBpd; and
|
|
·
|
completion
of our first horizontal East Texas Haynesville shale well with an initial
thirty-day average production rate of over 11 MMcfpd,
gross.
|
|
·
|
sanctioned
Aseng field oil development in Block I offshore Equatorial
Guinea;
|
|
·
|
successful
exploration well and appraisal offshore Israel at Tamar, our largest
discovery to date;
|
|
·
|
executed
two letters of intent to sell natural gas from the Tamar field offshore Israel with
expected gross revenues of over $10
billion;
|
|
·
|
additional
natural gas discovery offshore Israel at
Dalit;
|
|
·
|
first
oil discovery on Block O offshore Equatorial Guinea at the Carmen
prospect;
|
|
·
|
realized
record natural gas prices in Israel;
and
|
|
·
|
completed
field optimization efforts at the Dumbarton field and brought on line the
first well at Lochranza in the North
Sea.
|
|
·
|
overall
level and timing of capital expenditures which, as discussed below, and
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 and in the North
Sea;
|
|
·
|
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;
|
|
·
|
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;
|
|
·
|
successful
closing on purchase of additional US Rocky Mountain
assets;
|
|
·
|
variations
in North Sea sales volumes due to potential FPSO downtime and timing of
liftings;
|
|
·
|
seasonal
variations in rainfall in Ecuador that affect our natural gas-to-power
project;
|
|
·
|
potential
hurricane-related volume curtailments in the deepwater 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
Mountain area of our US operations;
|
|
·
|
potential
volume curtailments in Ecuador due to unsettled economic and political
environment;
|
|
·
|
impact
of asset purchases;
|
|
·
|
timing
of significant project completion and initial production;
and
|
|
·
|
impact
of sales of non-core operating
assets.
|
|
·
|
We are subject to various
governmental regulations and environmental risks that may cause us to
incur substantial costs;
|
|
·
|
Increased regulation of
business practices could result in increased operating costs;
and
|
|
·
|
The
adoption of pending climate change legislation could result in increased
operating costs, create delays in our obtaining air pollution permits for
new or modified facilities, and reduce demand for the crude oil and
natural gas we produce.
|
Year
Ended December 31,
|
||||||||||
2009
|
2008
|
2007
|
||||||||
(millions,
except per share)
|
||||||||||
Total
Revenues
|
$ | 2,313 | $ | 3,901 | $ | 3,272 | ||||
Total
Operating Expenses
|
2,371 | 2,266 | 1,777 | |||||||
Operating
Income
(Loss)
|
(58 | ) | 1,635 | 1,495 | ||||||
Total
Other (Income) Expense
|
206 | (426 | ) | 127 | ||||||
Income
(Loss) Before Income Taxes
|
(264 | ) | 2,061 | 1,368 | ||||||
Net
Income (Loss)
|
(131 | ) | 1,350 | 944 | ||||||
Earnings
(Loss) Per Share
|
||||||||||
Basic
|
$ | (0.75 | ) | $ | 7.83 | $ | 5.52 | |||
Diluted
|
(0.75 | ) | 7.58 | 5.45 |
|
·
|
$1.6 billion
decrease in total revenues due primarily to lower commodity
prices;
|
|
·
|
$110
million mark-to-market loss on derivative
instruments;
|
|
·
|
$604
million asset impairment charges;
and
|
|
·
|
$25
million increase in DD&A
expense;
|
|
·
|
$86
million refund
of deepwater Gulf of Mexico royalties plus interest of $11
million;
|
|
·
|
$69
million decrease in total production costs;
and
|
|
·
|
$73
million decrease in exploration
expense.
|
|
·
|
$629 million
increase in total revenues due primarily to higher commodity prices;
and
|
|
·
|
$440
million mark-to-market gain on derivative
instruments;
|
|
·
|
$294
million asset impairment charges;
|
|
·
|
$106
million increase in total production
costs;
|
|
·
|
$55
million increase in DD&A expense;
and
|
|
·
|
$38
million write-down of receivable from Semcrude,
L.P.
|
Crude
Oil and Condensate
|
Natural
Gas
|
NGLs
(1)
|
Total
|
||||||||||
(millions)
|
|||||||||||||
2007
Sales Revenues
|
$ | 1,694 | $ | 1,272 | $ | - | $ | 2,966 | |||||
Changes
due to
|
|||||||||||||
Increase
(Decrease) in Sales Volumes
|
(152 | ) | 165 | 175 | 188 | ||||||||
Increase
in Sales Prices Before Hedging
|
701 | 73 | - | 774 | |||||||||
Change
in Amounts Reclassified from AOCL
|
(142 | ) | (135 | ) | - | (277 | ) | ||||||
2008
Sales Revenues
|
2,101 | 1,375 | 175 | 3,651 | |||||||||
Changes
due to
|
|||||||||||||
Increase
(Decrease) in Sales Volumes
|
(232 | ) | 15 | - | (217 | ) | |||||||
Decrease
in Sales Prices Before Hedging
|
(915 | ) | (655 | ) | (77 | ) | (1,647 | ) | |||||
Change
in Amounts Reclassified from AOCL
|
307 | (34 | ) | - | 273 | ||||||||
2009
Sales Revenues
|
$ | 1,261 | $ | 701 | $ | 98 | $ | 2,060 |
(1)
|
For
2007, US NGL sales volumes were included with natural gas
volumes. Effective in 2008, we began reporting US NGLs
separately, which lowered the comparative natural gas sales revenues from
2007 to 2008 and 2009.
|
Average
daily sales volumes and average realized sales prices were as
follows:
|
Sales
Volumes
|
Average
Realized Sales Prices
|
|||||||||||||||||||||
Crude
Oil & Condensate (MBpd)
|
Natural
Gas (MMcfpd)
|
NGLs
(MBpd)
(1)
|
Total
(Boepd)
|
Crude
Oil & Condensate
(Per
Bbl)
|
Natural
Gas
(Per
Mcf)
|
NGLs
(Per Bbl)
|
||||||||||||||||
Year
Ended December 31, 2009
|
||||||||||||||||||||||
United
States (2)
|
37 | 397 | 10 | 113 | $ | 55.19 | $ | 3.61 | $ | 27.96 | ||||||||||||
Equatorial
Guinea (3)
|
14 | 239 | - | 54 | 55.94 | 0.27 | - | |||||||||||||||
Israel
|
- | 114 | - | 19 | - | 3.47 | - | |||||||||||||||
North
Sea
|
7 | 5 | - | 8 | 59.51 | 5.75 | - | |||||||||||||||
Ecuador
(4)
|
- | 26 | - | 4 | - | - | - | |||||||||||||||
China
|
4 | - | - | 4 | 54.40 | - | - | |||||||||||||||
Total
Consolidated Operations
|
62 | 781 | 10 | 202 | 55.76 | 2.54 | 27.96 | |||||||||||||||
Equity
Investees (5)
|
2 | - | 6 | 8 | 59.51 | - | 36.03 | |||||||||||||||
Total
|
64 | 781 | 16 | 210 | $ | 55.87 | $ | 2.54 | $ | 31.20 | ||||||||||||
Year
Ended December 31, 2008
|
||||||||||||||||||||||
United
States (2)
|
40 | 395 | 9 | 116 | $ | 75.53 | $ | 8.12 | $ | 50.15 | ||||||||||||
Equatorial
Guinea (3)
|
15 | 206 | - | 49 | 88.95 | 0.27 | - | |||||||||||||||
Israel
|
- | 139 | - | 23 | - | 3.10 | - | |||||||||||||||
North
Sea
|
10 | 5 | - | 11 | 100.56 | 10.54 | - | |||||||||||||||
Ecuador
(4)
|
- | 22 | - | 4 | - | - | - | |||||||||||||||
China
|
4 | - | - | 4 | 82.66 | - | - | |||||||||||||||
Total
Consolidated Operations
|
69 | 767 | 9 | 207 | 82.60 | 5.04 | 50.15 | |||||||||||||||
Equity
Investees (5)
|
2 | - | 6 | 8 | 96.77 | - | 58.81 | |||||||||||||||
Total
|
71 | 767 | 15 | 215 | $ | 82.96 | $ | 5.04 | $ | 53.45 | ||||||||||||
Year
Ended December 31, 2007
|
||||||||||||||||||||||
United
States (2)
|
42 | 412 | - | 111 | $ | 53.22 | $ | 7.51 | $ | - | ||||||||||||
Equatorial
Guinea (3)
|
15 | 132 | - | 37 | 71.27 | 0.29 | - | |||||||||||||||
Israel
|
- | 111 | - | 18 | - | 2.79 | - | |||||||||||||||
North
Sea
|
13 | 6 | - | 14 | 76.47 | 6.54 | - | |||||||||||||||
Ecuador
(4)
|
- | 26 | - | 4 | - | - | - | |||||||||||||||
China
|
4 | - | - | 4 | 58.79 | - | - | |||||||||||||||
Argentina
|
3 | - | - | 3 | 46.79 | - | - | |||||||||||||||
Total
Consolidated Operations
|
77 | 687 | - | 191 | 60.61 | 5.26 | - | |||||||||||||||
Equity
Investees (5)
|
2 | - | 6 | 8 | 74.87 | - | 48.87 | |||||||||||||||
Total
|
79 | 687 | 6 | 199 | $ | 60.94 | $ | 5.26 | $ | 48.87 |
(1)
|
Effective
in 2008, we began reporting US NGLs separately, which has lowered the
comparative natural gas sales volumes from 2007 to 2008 and 2009. For
2007, US NGL sales volumes were included with natural gas
volumes.
|
(2)
|
Average
realized crude oil and condensate prices reflect reductions of $2.13 per
Bbl for 2009, $22.06 per Bbl for 2008, and $13.68 per Bbl for 2007 from
hedging activities. Average realized natural gas prices reflect increases
of $0.23 per Mcf for 2008 and $1.12 per Mcf for 2007 from hedging
activities. The effect of hedging activities on the average realized
natural gas price for 2009 was de minimis. The price increases and
reductions resulted from hedge gains and losses that had been previously
deferred in accumulated other comprehensive income or loss
(AOCL).
|
(3)
|
Average
realized crude oil and condensate prices reflect reductions of $5.57 per
Bbl for 2009, $7.59 per Bbl for 2008 and $2.19 per Bbl for 2007 from
hedging activities. The price reductions resulted from hedge
losses that had been previously deferred in AOCL. 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.
|
(4)
|
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 Electricity Sales
and Expense below.
|
(5)
|
Volumes
represent sales of condensate and LPG from the Alba Plant in Equatorial
Guinea. See Income from Equity Method Investees
below.
|
Commodity
Price Increase (Decrease)
|
|||||||||||||
Crude
Oil & Condensate
|
Natural
Gas
|
Crude
Oil & Condensate
|
Natural
Gas
|
||||||||||
2009
|
2008
|
||||||||||||
(Per
Bbl)
|
(Per
Mcf)
|
(Per
Bbl)
|
(Per
Mcf)
|
||||||||||
Year
Ended December 31,
|
|||||||||||||
United
States
|
$ | 12.26 | $ | 1.73 | $ | (3.85 | ) | $ | (0.07 | ) | |||
Equatorial
Guinea
|
15.36 | - | (2.97 | ) | - | ||||||||
Total
Consolidated Operations
|
10.86 | 0.91 | (2.85 | ) | (0.04 | ) | |||||||
Total
|
10.55 | 0.91 | (2.77 | ) | (0.04 | ) |
Year
Ended December 31,
|
||||||||||
2009
|
2008
|
2007
|
||||||||
Net
Income (in millions)
|
||||||||||
AMPCO
and Affiliates
|
$ | 18 | $ | 56 | $ | 83 | ||||
Alba
Plant
|
66 | 118 | 128 | |||||||
Dividends
(in millions)
|
||||||||||
AMPCO
and Affiliates
|
29 | 65 | 97 | |||||||
Alba
Plant
|
63 | 156 | 132 | |||||||
Sales
Volumes
|
||||||||||
Methanol
(MMgal)
|
145 | 119 | 161 | |||||||
Condensate
(MBopd)
|
2 | 2 | 2 | |||||||
LPG
(MBpd)
|
6 | 6 | 6 | |||||||
Average
Realized Prices
|
||||||||||
Methanol
(per gallon)
|
$ | 0.60 | $ | 1.25 | $ | 1.09 | ||||
Condensate
(per Bbl)
|
59.51 | 96.77 | 74.87 | |||||||
LPG
(per Bbl)
|
36.03 | 58.81 | 48.87 |
Total
per BOE
|
Total
|
United
States
|
West
Africa
|
Eastern
Mediter-ranean
|
North
Sea
|
Other
Int'l (1)
|
||||||||||||||||
(millions,
except per unit)
|
||||||||||||||||||||||
Year
Ended December 31, 2009
|
||||||||||||||||||||||
Lease
Operating Expense (2)
|
$ | 5.05 | $ | 372 | $ | 258 | $ | 45 | $ | 9 | $ | 43 | $ | 17 | ||||||||
Production
and Ad Valorem Taxes
|
1.28 | 94 | 81 | - | - | - | 13 | |||||||||||||||
Transportation
Expense
|
0.80 | 59 | 52 | - | - | 4 | 3 | |||||||||||||||
Total
Production Costs (3)
|
$ | 7.13 | $ | 525 | $ | 391 | $ | 45 | $ | 9 | $ | 47 | $ | 33 | ||||||||
Total
Production Costs per BOE
|
$ | 7.13 | $ | 9.51 | $ | 2.30 | $ | 1.36 | $ | 17.50 | $ | 10.27 | ||||||||||
Year
Ended December 31, 2008
|
||||||||||||||||||||||
Lease
Operating Expense (2)
|
$ | 4.90 | $ | 371 | $ | 257 | $ | 39 | $ | 9 | $ | 53 | $ | 13 | ||||||||
Production
and Ad Valorem Taxes
|
2.19 | 166 | 135 | - | - | - | 31 | |||||||||||||||
Transportation
Expense
|
0.75 | 57 | 49 | - | - | 7 | 1 | |||||||||||||||
Total
Production Costs (3)
|
$ | 7.84 | $ | 594 | $ | 441 | $ | 39 | $ | 9 | $ | 60 | $ | 45 | ||||||||
Total
Production Costs per BOE
|
$ | 7.84 | $ | 10.43 | $ | 2.17 | $ | 1.07 | $ | 14.30 | $ | 15.94 | ||||||||||
Year
Ended December 31, 2007
|
||||||||||||||||||||||
Lease
Operating Expense (2)
|
$ | 4.62 | $ | 322 | $ | 213 | $ | 39 | $ | 8 | $ | 38 | $ | 24 | ||||||||
Production
and Ad Valorem Taxes
|
1.63 | 114 | 91 | - | - | - | 23 | |||||||||||||||
Transportation
Expense
|
0.74 | 52 | 40 | - | - | 11 | 1 | |||||||||||||||
Total
Production Costs (3)
|
$ | 6.99 | $ | 488 | $ | 344 | $ | 39 | $ | 8 | $ | 49 | $ | 48 | ||||||||
Total
Production Costs per BOE
|
$ | 6.99 | $ | 8.49 | $ | 2.89 | $ | 1.14 | $ | 9.81 | $ | 12.06 |
(1)
|
Other
international includes 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 and repair expense.
|
(3)
|
Consolidated
unit rates exclude sales volumes and costs attributable to equity method
investees.
|
Total
|
United
States
|
West
Africa
|
Eastern
Mediter-ranean
|
North
Sea
|
Other
Int'l, Corporate (1)
|
|||||||||||||||||||
(millions)
|
||||||||||||||||||||||||
Year
Ended December 31, 2009
|
||||||||||||||||||||||||
Dry
Hole Expense
|
$ | 11 | $ | 8 | $ | 3 | $ | - | $ | - | $ | - | ||||||||||||
Seismic
|
62 | 47 | - | 15 | - | - | ||||||||||||||||||
Staff
Expense
|
65 | 13 | 10 | 1 | 2 | 39 | ||||||||||||||||||
Other
|
6 | 6 | - | - | - | - | ||||||||||||||||||
Total
Exploration Expense
|
$ | 144 | $ | 74 | $ | 13 | $ | 16 | $ | 2 | $ | 39 | ||||||||||||
Year
Ended December 31, 2008
|
||||||||||||||||||||||||
Dry
Hole Expense
|
$ | 84 | $ | 42 | $ | 1 | $ | - | $ | 8 | $ | 33 | ||||||||||||
Seismic
|
57 | 50 | - | 3 | 4 | - | ||||||||||||||||||
Staff
Expense
|
62 | 14 | 7 | 1 | 5 | 35 | ||||||||||||||||||
Other
|
14 | 13 | - | - | 1 | - | ||||||||||||||||||
Total
Exploration Expense
|
$ | 217 | $ | 119 | $ | 8 | $ | 4 | $ | 18 | $ | 68 | ||||||||||||
Year
Ended December 31, 2007
|
||||||||||||||||||||||||
Dry
Hole Expense
|
$ | 90 | $ | 50 | $ | 40 | $ | - | $ | - | $ | - | ||||||||||||
Seismic
|
65 | 55 | 1 | 1 | 8 | - | ||||||||||||||||||
Staff
Expense
|
46 | 12 | 2 | 1 | 9 | 22 | ||||||||||||||||||
Other
|
18 | 17 | - | - | - | 1 | ||||||||||||||||||
Total
Exploration Expense
|
$ | 219 | $ | 134 | $ | 43 | $ | 2 | $ | 17 | $ | 23 |
(1)
|
Other
international includes Ecuador, China, Argentina (through February 2008),
Suriname, Cyprus, and other international new
ventures.
|
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions,
except unit rate)
|
||||||||||||
United
States
|
$ | 689 | $ | 646 | $ | 580 | ||||||
Equatorial
Guinea
|
38 | 34 | 25 | |||||||||
Israel
|
20 | 24 | 18 | |||||||||
North
Sea
|
34 | 55 | 81 | |||||||||
Other
International, Corporate, and Other
|
35 | 32 | 32 | |||||||||
Total
DD&A Expense (1)
|
$ | 816 | $ | 791 | $ | 736 | ||||||
Unit
Rate per BOE
(2)
|
$ | 11.08 | $ | 10.44 | $ | 10.55 |
(1)
|
DD&A
expense includes accretion of discount on asset retirement obligations of
$14 million in 2009, $10 million in 2008, and $8 million in
2007.
|
(2)
|
Consolidated
unit rates exclude sales volumes and costs attributable to equity method
investees.
|
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
G&A
Expense (in millions)
|
$ | 237 | $ | 236 | $ | 206 | ||||||
Unit
Rate per BOE (1)
|
$ | 3.22 | $ | 3.12 | $ | 2.96 |
(1)
|
Consolidated
unit rates exclude sales volumes and costs attributable to equity method
investees.
|
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions)
|
||||||||||||
Asset
Impairments
|
$ | 604 | $ | 294 | $ | 4 |
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions)
|
||||||||||||
Other
Operating (Income) Expense, Net
|
$ | 45 | $ | 134 | $ | 124 |
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions,
except as noted)
|
||||||||||||
Electricity
Sales
|
$ | 72 | $ | 56 | $ | 71 | ||||||
Electricity
Generation Expense
|
18 | 57 | 57 | |||||||||
Operating
Income
|
54 | (1 | ) | 14 | ||||||||
Power
Generation (GW)
|
902 | 749 | 912 | |||||||||
Average
Power Price ($/Kwh)
|
$ | 0.080 | $ | 0.074 | $ | 0.078 |
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions)
|
||||||||||||
(Gain)
Loss on Commodity Derivative Instruments
|
$ | 110 | $ | (440 | ) | $ | (2 | ) |
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions,
except per unit)
|
||||||||||||
Interest
Expense
|
$ | 129 | $ | 102 | $ | 130 | ||||||
Capitalized
Interest
|
(45 | ) | (33 | ) | (17 | ) | ||||||
Interest
Expense, Net
|
$ | 84 | $ | 69 | $ | 113 | ||||||
Unit
Rate, per BOE
|
$ | 1.13 | $ | 0.91 | $ | 1.56 |
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions)
|
||||||||||||
Other
Non-operating (Income) Expense, Net
|
$ | 12 | $ | (55 | ) | $ | 16 |
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Income
Tax Provision (Benefit) (millions)
|
$ | (133 | ) | $ | 711 | $ | 424 | |||||
Effective
Rate
|
50 | % | 35 | % | 31 | % |
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(MMBOE)
|
||||||||||||
Proved
Reserves Beginning of Year
|
864 | 880 | 835 | |||||||||
Revisions
of Previous Estimates
|
(64 | ) | (44 | ) | 30 | |||||||
Extensions,
Discoveries and Other Additions
|
95 | 98 | 90 | |||||||||
Purchase
of Minerals in Place
|
2 | 15 | - | |||||||||
Sale
of Minerals in Place
|
- | (7 | ) | (2 | ) | |||||||
Production
|
(77 | ) | (78 | ) | (73 | ) | ||||||
Proved
Reserves End of Year
|
820 | 864 | 880 |
December
31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions,
except percentages)
|
||||||||||||
Cash
and Cash Equivalents
|
$ | 1,014 | $ | 1,140 | $ | 660 | ||||||
Amount
Available to be Borrowed Under Credit Facility
|
1,718 | 494 | 920 | |||||||||
Total
Liquidity
|
$ | 2,732 | $ | 1,634 | $ | 1,580 | ||||||
Total
Debt (Excluding Unamortized Discount)
|
$ | 2,045 | $ | 2,270 | $ | 1,880 | ||||||
Total
Shareholders' Equity
|
6,157 | 6,309 | 4,809 | |||||||||
Debt-to-Capital
Ratio (1)
|
25 | % | 26 | % | 28 | % |
(1)
|
We define our ratio of
debt-to-book capital as total debt (which includes both long-term debt,
excluding unamortized discount, and short-term borrowings) divided by the
sum of total debt plus shareholders’
equity.
|
Summary
cash flow information is as
follows:
|
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions)
|
||||||||||||
Total
Cash Provided By (Used in)
|
||||||||||||
Operating
Activities
|
$ | 1,508 | $ | 2,285 | $ | 2,017 | ||||||
Investing
Activities
|
(1,265 | ) | (2,132 | ) | (1,403 | ) | ||||||
Financing
Activities
|
(369 | ) | 327 | (107 | ) | |||||||
Increase
(Decrease) in Cash and Cash Equivalents
|
$ | (126 | ) | $ | 480 | $ | 507 |
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions)
|
||||||||||||
Acquisition,
Capital and Exploration Expenditures
|
||||||||||||
Unproved
Property Acquisition (1)
|
$ | 92 | $ | 302 | $ | 146 | ||||||
Proved
Property Acquisition (2)
|
(5 | ) | 256 | 11 | ||||||||
Exploration
|
242 | 448 | 372 | |||||||||
Development
|
881 | 1,193 | 1,175 | |||||||||
Corporate
and Other
|
107 | 65 | 35 | |||||||||
Total
|
$ | 1,317 | $ | 2,264 | $ | 1,739 | ||||||
Non-cash Capital Lease Accrual (3) | $ | 29 | $ | - | $ | - |
(1)
|
Unproved
property acquisition cost for 2009 includes $56 million for deepwater Gulf
of Mexico lease blocks and the remainder primarily for other onshore US
lease acquisition. Unproved property acquisition cost for 2008 includes
$179 million for deepwater Gulf of Mexico lease blocks, $38 million
related to the Mid-continent
acquisition, $79 million related to additional onshore US lease
acquisitions and $6 million related to international lease
acquisitions.
|
(2)
|
Proved
property acquisition cost for 2008 includes $254 million related to the
Mid-continent acquisition.
|
(3)
|
Relates
to estimated construction in progress to date on an FPSO to be used in the
development of the Aseng field in Equatorial
Guinea.
|
·
|
$225 million
decrease in total principal amount of debt from the balance at December
31, 2008;
|
|
·
|
$131 million
decrease in shareholders’ equity from current year net loss;
and
|
|
·
|
$126
million decrease in shareholders’ equity from dividends
paid.
|
Total
|
2010
|
2011
and 2012
|
2013
and 2014
|
2015
and beyond
|
||||||||||||||||
(millions)
|
||||||||||||||||||||
Long-Term
Debt (Excluding Interest) (1)
|
$ | 2,016 | $ | - | $ | 382 | $ | 200 | $ | 1,434 | ||||||||||
Obligation
Under FPSO Lease (2)
|
468 | - | 35 | 138 | 295 | |||||||||||||||
Drilling
and Equipment Obligations (3)
|
||||||||||||||||||||
United
States
|
461 | 259 | 202 | - | - | |||||||||||||||
International
|
269 | 147 | 122 | - | - | |||||||||||||||
Purchase
Obligations (4)
|
304 | 265 | 39 | - | - | |||||||||||||||
Throughput
Agreement (5)
|
81 | 19 | 38 | 24 | - | |||||||||||||||
Transportation
and Gathering (6)
|
40 | 11 | 17 | 9 | 3 | |||||||||||||||
Operating
Lease Obligations (7)
|
83 | 12 | 19 | 21 | 31 | |||||||||||||||
Other
Long-Term Liabilities (8)
|
||||||||||||||||||||
Asset
Retirement Obligations (9)
|
232 | 51 | 31 | 7 | 143 | |||||||||||||||
Commodity
Derivative Instruments (10)
|
117 | 100 | 17 | - | - | |||||||||||||||
Total
Contractual Obligations
|
$ | 4,071 | $ | 864 | $ | 902 | $ | 399 | $ | 1,906 |
(1)
|
Long-term debt
excludes obligation under FPSO lease. Based on the total debt
balance, scheduled maturities and interest rates in effect at December 31,
2009, our cash payments for interest would be $128 million in 2010,
$128 million in 2011, $128 million in 2012, $126 million in
2013, $121 million in 2014 and $1.2 billion for the remaining years for a
total of $1.8 billion. See Item 8. Financial Statements and
Supplementary Data – Note 8. Debt.
|
(2)
|
The FPSO is
currently under construction. Annual lease payments, net to our
interest, exclude regular maintenance and operational costs, and will
begin when the FPSO initiates producing operations. These payments are
also subject to change based on change orders implemented during the
construction period, final accounting treatment, and other
factors. See Item 8. Financial Statements and Supplementary
Data – Note 8. Debt.
|
(3)
|
Drilling
and equipment obligations represent contractual agreements with third
party service providers to procure drilling rigs and other related
equipment for developmental and exploratory drilling
activities. See Item 8. Financial Statements and Supplementary
Data – Note 17. Commitments and
Contingencies.
|
(4)
|
Purchase
obligations represent agreements to purchase goods or services that are
enforceable, are legally binding and specify all significant terms,
including fixed and minimum quantities to be purchased; fixed, minimum or
variable price provisions; and the approximate timing of the transaction.
See Item 8. Financial Statements and Supplementary Data – Note 17.
Commitments and Contingencies.
|
(5)
|
We
have a five-year throughput agreement on a new interstate crude oil
transportation pipeline system running from Weld County, Colorado to
Cushing, Oklahoma, which became operational in 2009. See Item 8. Financial
Statements and Supplementary Data – Note 17. Commitments and
Contingencies.
|
(6)
|
Transportation
and gathering obligations represent minimum charges for our firm
transportation and gathering agreements. See Item 8. Financial
Statements and Supplementary Data – Note 17. Commitments and
Contingencies.
|
(7)
|
Operating
lease obligations represent non-cancelable leases for office buildings and
facilities and oil and gas operations equipment used in our daily
operations. See Item 8. Financial Statements and Supplementary
Data – Note 17. Commitments and
Contingencies.
|
(8)
|
The
table excludes deferred compensation liabilities of $213 million and
accrued benefit costs of $76 million as specific payment dates are
unknown. See Item 8. Financial Statements and Supplementary Data – Note
12. Benefit Plans.
|
(9)
|
Asset
retirement obligations are discounted. See Item 8. Financial Statements
and Supplementary Data – Note 10. Asset Retirement
Obligations.
|
(10)
|
Amount
represents open commodity derivative instruments that were in a net
payable position with the counterparty at December 31, 2009. Our remaining
commodity derivative instruments were in a net receivable position at
December 31, 2009. See Item 8. Financial Statements and Supplementary Data
– Note 6. Derivative Instruments and Hedging
Activities.
|
Interest
Rate Risk
|
Foreign
Currency Risk
|
Consolidated
Financial Statements of Noble Energy, Inc.
|
|
64
|
|
65
|
|
66
|
|
67
|
|
68
|
|
69
|
|
70
|
|
71
|
|
Notes
to Consolidated Financial Statements
|
|
Note 1. Nature of Operations | 72 |
Note 2. Summary of Significant Accounting Policies | 72 |
Note 3. Asset Impairments | 82 |
Note 4. Acquisitions and Divestitures | 83 |
Note 5. Fair Value Measurements and Disclosures | 83 |
Note 6. Derivative Instruments and Hedging Activities | 85 |
Note 7. Capitalized Exploratory Well Costs | 88 |
Note 8. Long-Term Debt | 89 |
Note 9. Income Taxes | 91 |
Note 10. Asset Retirement Obligations | 93 |
Note 11. Equity Method Investments | 94 |
Note 12. Benefit Plans | 95 |
Note 13. Stock-Based Compensation | 100 |
Note 14. Earnings Per Share | 103 |
Note 15. Segment Information | 104 |
Note 16. Additional Shareholders' Equity Information | 106 |
Note 17. Commitments and Contingencies | 106 |
108
|
|
118
|
|
Noble
Energy, Inc.
|
Noble
Energy, Inc. and Subsidiaries
|
||||||||||||
Consolidated Statements of
Operations
|
||||||||||||
(in
millions, except per share amounts)
|
||||||||||||
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Revenues
|
||||||||||||
Oil,
Gas and NGL Sales
|
$ | 2,060 | $ | 3,651 | $ | 2,966 | ||||||
Income
from Equity Method Investees
|
84 | 174 | 211 | |||||||||
Other
Revenues
|
169 | 76 | 95 | |||||||||
Total
Revenues
|
2,313 | 3,901 | 3,272 | |||||||||
Costs
and Expenses
|
||||||||||||
Production
Expense
|
525 | 594 | 488 | |||||||||
Exploration
Expense
|
144 | 217 | 219 | |||||||||
Depreciation,
Depletion and Amortization
|
816 | 791 | 736 | |||||||||
General
and Administrative
|
237 | 236 | 206 | |||||||||
Asset
Impairments
|
604 | 294 | 4 | |||||||||
Other
Operating Expense, Net
|
45 | 134 | 124 | |||||||||
Total
Operating Expenses
|
2,371 | 2,266 | 1,777 | |||||||||
Operating
Income
(Loss)
|
(58 | ) | 1,635 | 1,495 | ||||||||
Other
(Income) Expense
|
||||||||||||
(Gain)
Loss on Commodity Derivative Instruments
|
110 | (440 | ) | (2 | ) | |||||||
Interest,
Net of Amount Capitalized
|
84 | 69 | 113 | |||||||||
Other
Non-Operating (Income) Expense, Net
|
12 | (55 | ) | 16 | ||||||||
Total
Other (Income) Expense
|
206 | (426 | ) | 127 | ||||||||
Income
(Loss) Before Income Taxes
|
(264 | ) | 2,061 | 1,368 | ||||||||
Income
Tax Provision (Benefit)
|
(133 | ) | 711 | 424 | ||||||||
Net
Income (Loss)
|
$ | (131 | ) | $ | 1,350 | $ | 944 | |||||
Earnings
(Loss) Per Share, Basic
|
$ | (0.75 | ) | $ | 7.83 | $ | 5.52 | |||||
Earnings
(Loss) Per Share, Diluted
|
(0.75 | ) | 7.58 | 5.45 | ||||||||
Weighted
Average Number of Shares Outstanding, Basic
|
173 | 173 | 171 | |||||||||
Weighted
Average Number of Shares Outstanding, Diluted
|
173 | 176 | 173 | |||||||||
The
accompanying notes are an integral part of these financial
statements.
|
Noble
Energy, Inc.
|
||||||||
Consolidated Balance Sheets
|
||||||||
(in
millions)
|
||||||||
December
31,
|
||||||||
2009
|
2008
|
|||||||
ASSETS
|
||||||||
Current
Assets
|
||||||||
Cash
and Cash Equivalents
|
$ | 1,014 | $ | 1,140 | ||||
Accounts
Receivable, Net
|
465 | 423 | ||||||
Commodity
Derivative Assets, Current
|
13 | 437 | ||||||
Other
Current Assets
|
186 | 158 | ||||||
Total
Assets, Current
|
1,678 | 2,158 | ||||||
Property,
Plant and Equipment
|
||||||||
Oil
and Gas Properties (Successful Efforts Method of
Accounting)
|
12,584 | 11,963 | ||||||
Property,
Plant and Equipment, Other
|
240 | 175 | ||||||
Total
Property, Plant and Equipment, Gross
|
12,824 | 12,138 | ||||||
Accumulated
Depreciation, Depletion and Amortization
|
(3,908 | ) | (3,134 | ) | ||||
Total
Property, Plant and Equipment, Net
|
8,916 | 9,004 | ||||||
Goodwill
|
758 | 759 | ||||||
Other
Noncurrent Assets
|
455 | 463 | ||||||
Total
Assets
|
$ | 11,807 | $ | 12,384 | ||||
LIABILITIES
AND SHAREHOLDERS’ EQUITY
|
||||||||
Current
Liabilities
|
||||||||
Accounts
Payable - Trade
|
$ | 548 | $ | 579 | ||||
Other
Current Liabilities
|
442 | 595 | ||||||
Total
Liabilities, Current
|
990 | 1,174 | ||||||
Long-Term
Debt
|
2,037 | 2,241 | ||||||
Deferred
Income Taxes, Noncurrent
|
2,076 | 2,174 | ||||||
Other
Noncurrent Liabilities
|
547 | 486 | ||||||
Total
Liabilities
|
5,650 | 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; 194 Million
and 192 Million Shares Issued, Respectively
|
645 | 641 | ||||||
Additional
Paid in Capital
|
2,260 | 2,193 | ||||||
Accumulated
Other Comprehensive Loss
|
(75 | ) | (110 | ) | ||||
Treasury
Stock, at Cost; 19 Million Shares
|
(615 | ) | (614 | ) | ||||
Retained
Earnings
|
3,942 | 4,199 | ||||||
Total
Shareholders’ Equity
|
6,157 | 6,309 | ||||||
Total
Liabilities and Shareholders’ Equity
|
$ | 11,807 | $ | 12,384 | ||||
The
accompanying notes are an integral part of these financial
statements.
|
Noble
Energy, Inc.
|
||||||||||||
Consolidated Statements of Cash
Flows
|
||||||||||||
(in
millions)
|
||||||||||||
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Cash
Flows From Operating Activities
|
||||||||||||
Net
Income (Loss)
|
$ | (131 | ) | $ | 1,350 | $ | 944 | |||||
Adjustments
to Reconcile Net Income (Loss) to Net Cash Provided by Operating
Activities
|
||||||||||||
Depreciation,
Depletion and Amortization
|
816 | 791 | 736 | |||||||||
Dry
Hole Expense
|
11 | 84 | 90 | |||||||||
Asset
Impairments
|
604 | 294 | 4 | |||||||||
Deferred
Income Taxes
|
(296 | ) | 359 | 292 | ||||||||
Income
from Equity Method Investees
|
(84 | ) | (174 | ) | (211 | ) | ||||||
Dividends
from Equity Method Investees
|
92 | 221 | 227 | |||||||||
Unrealized
(Gain) Loss on Commodity Derivative Instruments
|
606 | (522 | ) | (2 | ) | |||||||
Settlement
of Previously Recognized Hedge Losses
|
- | (194 | ) | (183 | ) | |||||||
Allowance
for Doubtful Accounts
|
(18 | ) | 49 | 14 | ||||||||
Net
Gain on Asset Sales
|
(22 | ) | (5 | ) | (12 | ) | ||||||
(Gain)
Loss on Involuntary Conversion
|
(9 | ) | 9 | 51 | ||||||||
Other
Adjustments for Noncash Items Included in Income
|
86 | 26 | 91 | |||||||||
Changes
in Operating Assets and Liabilities
|
||||||||||||
(Increase)
Decrease in Accounts Receivable
|
(28 | ) | 121 | (22 | ) | |||||||
(Increase)
Decrease in Other Current Assets
|
(4 | ) | (17 | ) | 116 | |||||||
Increase
(Decrease) in Accounts Payable
|
(19 | ) | (142 | ) | 19 | |||||||
Increase
(Decrease) in Other Current Liabilities
|
(38 | ) | 67 | (158 | ) | |||||||
Increase
(Decrease) in Other Operating Assets and Liabilities, Net
|
(58 | ) | (32 | ) | 21 | |||||||
Net
Cash Provided by Operating Activities
|
1,508 | 2,285 | 2,017 | |||||||||
|
||||||||||||
Cash
Flows From Investing Activities
|
||||||||||||
Additions
to Property, Plant and Equipment
|
(1,268 | ) | (1,971 | ) | (1,414 | ) | ||||||
Acquisitions,
Net of Cash Acquired
|
- | (292 | ) | - | ||||||||
Proceeds
from Sale of Property, Plant and Equipment, and Other
|
3 | 131 | 11 | |||||||||
Net
Cash Used in Investing Activities
|
(1,265 | ) | (2,132 | ) | (1,403 | ) | ||||||
|
||||||||||||
Cash
Flows From Financing Activities
|
||||||||||||
Exercise
of Stock Options
|
17 | 27 | 25 | |||||||||
Excess
Tax Benefits from Stock-Based Awards
|
5 | 24 | 20 | |||||||||
Dividends
Paid, Common Stock
|
(126 | ) | (115 | ) | (75 | ) | ||||||
Purchase
of Treasury Stock
|
(1 | ) | (3 | ) | (102 | ) | ||||||
Proceeds
from Credit Facilities
|
340 | 951 | 280 | |||||||||
Repayment
of Credit Facilities
|
(1,564 | ) | (525 | ) | (255 | ) | ||||||
Proceeds
from Issuance of Senior Long-Term Debt
|
989 | - | - | |||||||||
Repayment
of Installment Note
|
(25 | ) | (25 | ) | - | |||||||
Repurchase
of Senior Debentures
|
(4 | ) | (7 | ) | - | |||||||
Net
Cash Provided by (Used in) Financing Activities
|
(369 | ) | 327 | (107 | ) | |||||||
Increase
(Decrease) in Cash and Cash Equivalents
|
(126 | ) | 480 | 507 | ||||||||
Cash
and Cash Equivalents at Beginning of Period
|
1,140 | 660 | 153 | |||||||||
Cash
and Cash Equivalents at End of Period
|
$ | 1,014 | $ | 1,140 | $ | 660 | ||||||
The
accompanying notes are an integral part of these financial
statements.
|
||||||||||||
Noble
Energy, Inc.
|
||||||||||||
Consolidated Statements of
Shareholders' Equity
|
||||||||||||
(in
millions)
|
||||||||||||
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Common
Stock
|
||||||||||||
Balance,
Beginning of Period
|
$ | 641 | $ | 636 | $ | 629 | ||||||
Exercise
of Stock Options
|
2 | 4 | 5 | |||||||||
Restricted
Stock Awards, Net
|
2 | 1 | 2 | |||||||||
Balance,
End of Period
|
645 | 641 | 636 | |||||||||
Capital
in Excess of Par Value
|
||||||||||||
Balance,
Beginning of Period
|
2,193 | 2,106 | 2,041 | |||||||||
Stock-Based
Compensation Expense
|
49 | 39 | 27 | |||||||||
Exercise
of Stock Options
|
15 | 23 | 20 | |||||||||
Tax
Benefits Related to Exercise of Stock Options
|
5 | 24 | 20 | |||||||||
Restricted
Stock Awards, Net
|
(2 | ) | (1 | ) | (2 | ) | ||||||
Rabbi
Trust Shares Sold
|
- | 2 | - | |||||||||
Balance,
End of Period
|
2,260 | 2,193 | 2,106 | |||||||||
Accumulated
Other Comprehensive Loss
|
||||||||||||
Balance,
Beginning of Period
|
(110 | ) | (284 | ) | (140 | ) | ||||||
Oil
and Gas Cash Flow Hedges
|
||||||||||||
Realized
Amounts Reclassified Into Earnings
|
36 | 207 | 33 | |||||||||
Unrealized
Change in Fair Value
|
- | - | (184 | ) | ||||||||
Net
Change in Other
|
(1 | ) | (33 | ) | 7 | |||||||
Balance,
End of Period
|
(75 | ) | (110 | ) | (284 | ) | ||||||
Treasury
Stock at Cost
|
||||||||||||
Balance,
Beginning of Period
|
(614 | ) | (613 | ) | (511 | ) | ||||||
Purchases
of Treasury Stock
|
(1 | ) | (3 | ) | (102 | ) | ||||||
Rabbi
Trust Shares Sold
|
- | 2 | - | |||||||||
Balance,
End of Period
|
(615 | ) | (614 | ) | (613 | ) | ||||||
Retained
Earnings
|
||||||||||||
Balance,
Beginning of Period
|
4,199 | 2,964 | 2,095 | |||||||||
Net
Income (Loss)
|
(131 | ) | 1,350 | 944 | ||||||||
Cash
Dividends ($0.720, $0.660 and $0.435 Per Share,
Respectively)
|
(126 | ) | (115 | ) | (75 | ) | ||||||
Balance,
End of Period
|
3,942 | 4,199 | 2,964 | |||||||||
Total
Shareholders' Equity
|
$ | 6,157 | $ | 6,309 | $ | 4,809 | ||||||
The
accompanying notes are an integral part of these financial
statements.
|
Noble
Energy, Inc.
|
||||||||||||
Consolidated Statements of Comprehensive
Income
|
||||||||||||
(in
millions)
|
||||||||||||
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Net
Income (Loss)
|
$ | (131 | ) | $ | 1,350 | $ | 944 | |||||
Other
Items of Comprehensive Income (Loss)
|
||||||||||||
Oil
and Gas Cash Flow Hedges
|
||||||||||||
Realized
Losses Reclassified Into Earnings
|
58 | 331 | 54 | |||||||||
Less
Tax
Benefit
|
(22 | ) | (124 | ) | (21 | ) | ||||||
Unrealized
Change in Fair Value
|
- | - | (295 | ) | ||||||||
Less
Tax Benefit
|
- | - | 111 | |||||||||
Net
Change in Other
|
(2 | ) | (52 | ) | 11 | |||||||
Less
Tax Provision (Benefit)
|
1 | 19 | (4 | ) | ||||||||
Other
Comprehensive Income (Loss)
|
35 | 174 | (144 | ) | ||||||||
Comprehensive
Income (Loss)
|
$ | (96 | ) | $ | 1,524 | $ | 800 | |||||
|
||||||||||||
The
accompanying notes are an integral part of these financial
statements.
|
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions)
|
||||||||||||
Other
Revenues
|
||||||||||||
Refund of Deepwater
Gulf of Mexico Royalties (1)
|
$ | 86 | $ | - | $ | - | ||||||
Electricity
Sales (2)
|
72 | 56 | 71 | |||||||||
Gathering,
Marketing and Processing (GMP) Revenues
|
11 | 20 | 24 | |||||||||
Total
|
$ | 169 | $ | 76 | $ | 95 | ||||||
Production
Expense
|
||||||||||||
Lease
Operating Expense
|
$ | 372 | $ | 371 | $ | 322 | ||||||
Production
and Ad Valorem Taxes
|
94 | 166 | 114 | |||||||||
Transportation
Expense
|
59 | 57 | 52 | |||||||||
Total
|
$ | 525 | $ | 594 | $ | 488 | ||||||
Other
Operating (Income) Expense, Net
|
||||||||||||
Net
Gain on Asset Sales (3)
|
$ | (22 | ) | $ | (5 | ) | $ | (12 | ) | |||
Electricity
Generation Expense (2)
|
18 | 57 | 57 | |||||||||
GMP
Expense
|
18 | 19 | 17 | |||||||||
Settlement
of Legal Proceedings (4)
|
9 | 1 | (1 | ) | ||||||||
(Gain)
Loss on Involuntary Conversion (5)
|
(9 | ) | 9 | 51 | ||||||||
Other,
Net (6)
|
31 | 53 | 12 | |||||||||
Total
|
$ | 45 | $ | 134 | $ | 124 | ||||||
Other
Non-Operating (Income) Expense, Net
|
||||||||||||
Deferred
Compensation (Income) Expense (7)
|
$ | 23 | $ | (32 | ) | $ | 33 | |||||
Interest
Income (8)
|
(13 | ) | (20 | ) | (19 | ) | ||||||
Other
(Income) Expense, Net
|
2 | (3 | ) | 2 | ||||||||
Total
|
$ | 12 | $ | (55 | ) | $ | 16 |
(1)
|
See
Refund of Deepwater Gulf of Mexico
Royalties below.
|
(2)
|
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 DD&A and
changes in the allowance for doubtful accounts. We recognized a net
decrease of $32 million in the allowance in 2009, and net increases of $11
million in 2008 and $14 million in 2007. See Allowance for Doubtful
Accounts below.
|
(3)
|
Includes
$24 million gain on sale of our interest in Argentina. In February 2008,
effective July 1, 2007, we sold our interest in Argentina for a sales
price of $117.5 million. Recognition of the gain on the sale
was deferred until second quarter 2009 when the Argentine government
approved the sale.
|
(4)
|
The
amount for 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.
|
(5)
|
The
amount for 2009 represents receipt of insurance claims related to
Hurricanes Katrina and Rita damage. The amount for 2008 represents interim
settlement of the replacement cost portion of the Hurricane Katrina
insurance claim. The amount for 2007 represents project costs in excess of
certain insurance coverage limitations related to hurricane cleanup costs
at our Gulf of Mexico Main Pass
asset.
|
(6)
|
Includes
write-downs of SemCrude L.P. (SemCrude) receivable of $12 million in 2009
and $38 million in 2008. SemCrude was a purchaser of our crude oil. See
Allowance for Doubtful Accounts below and Note
17. Commitments and Contingencies.
|
(7)
|
The
amount represents increases (decreases) in the fair value of shares of our
common stock held in a rabbi trust. See Note 12. Benefit
Plans.
|
(8)
|
Includes $11 million
interest income related to expected refund of deepwater Gulf of Mexico
royalties. See Refund of Deepwater Gulf of Mexico Royalties
below.
|
Balance Sheet
Information Additional
balance sheet information is as
follows:
|
December
31,
|
||||||||
2009
|
2008
|
|||||||
(millions)
|
||||||||
Accounts
Receivable, Net
|
||||||||
Commodity
Sales
|
$ | 205 | $ | 296 | ||||
Joint
Interest Billings
|
140 | 87 | ||||||
Refund of Deepwater
Gulf of Mexico Royalties
(1)
|
97 | - | ||||||
Marketing
and Trading Activities
|
25 | 130 | ||||||
Other
|
29 | 7 | ||||||
Allowance
for Doubtful Accounts (2)
|
(31 | ) | (97 | ) | ||||
Total
|
$ | 465 | $ | 423 | ||||
Other
Current Assets
|
||||||||
Inventories,
Current
|
$ | 89 | $ | 105 | ||||
Prepaid
Expenses and Other Assets, Current
|
65 | 27 | ||||||
Deferred Income Taxes, Net, Current | 32 | - | ||||||
Asset
Held for Sale (3)
|
- | 26 | ||||||
Total
|
$ | 186 | $ | 158 | ||||
Other
Noncurrent Assets
|
||||||||
Equity
Method Investments
|
$ | 303 | $ | 311 | ||||
Mutual
Fund Investments
|
108 | 84 | ||||||
Commodity
Derivative Assets, Noncurrent
|
1 | 33 | ||||||
Other
Assets, Noncurrent
|
43 | 35 | ||||||
Total
|
$ | 455 | $ | 463 |
(1)
|
See
Refund of Deepwater Gulf of
Mexico Royalties below.
|
(2)
|
See
Allowance for Doubtful Accounts
below.
|
(3)
|
Our remaining
non-core Gulf of Mexico shelf asset at Main Pass was
reclassified from held-for-sale to held-and-used and
impaired during first quarter 2009. See Note 3. Impairments and Note 4.
Acquisitions and Divestitures.
|
December
31,
|
||||||||
2009
|
2008
|
|||||||
(millions)
|
||||||||
Accounts
Payable - Trade
|
||||||||
Capital
Costs
|
$ | 277 | $ | 273 | ||||
Royalties
Payable
|
65 | 81 | ||||||
Marketing
and Trading Activities
|
76 | 159 | ||||||
Lease
Operating Expense
|
27 | 10 | ||||||
Other
|
103 | 56 | ||||||
Total
|
$ | 548 | $ | 579 | ||||
Other
Current Liabilities
|
||||||||
Production
and Ad Valorem Taxes
|
$ | 103 | $ | 114 | ||||
Commodity
Derivative Liabilities, Current
|
100 | 23 | ||||||
Income Taxes Payable | 60 | 130 | ||||||
Deferred Income Taxes, Net, Current | 1 | 142 | ||||||
Asset
Retirement Obligations, Current
|
51 | 27 | ||||||
Interest
Payable
|
37 | 9 | ||||||
Short-Term
Borrowings
|
- | 25 | ||||||
Deferred
Gain on Asset Sale, Current (1)
|
- | 24 | ||||||
Other
|
90 | 101 | ||||||
Total
|
$ | 442 | $ | 595 | ||||
Other
Noncurrent Liabilities
|
||||||||
Deferred
Compensation Liabilities, Noncurrent
|
$ | 213 | $ | 159 | ||||
Asset
Retirement Obligations, Noncurrent
|
181 | 184 | ||||||
Accrued
Benefit Costs, Noncurrent
|
77 | 81 | ||||||
Commodity
Derivative Liabilities, Noncurrent
|
17 | 2 | ||||||
Other
|
59 | 60 | ||||||
Total
|
$ | 547 | $ | 486 |
(1)
|
See
footnote (3) to Statements of Operations
Information above.
|
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions)
|
||||||||||||
Cash
Paid During the Year For
|
||||||||||||
Interest,
Net of Amount Capitalized
|
$ | 52 | $ | 76 | $ | 105 | ||||||
Income
Taxes Paid, Net
|
227 | 263 | 149 | |||||||||
Non-Cash
Financing and Investing Activities
|
||||||||||||
Increase
in Long-Term Obligation Related to FPSO Construction
|
29 | - | - | |||||||||
Issuance
of Notes for Property Interests
|
- | - | 50 |
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions)
|
||||||||||||
Balance,
Beginning of period
|
$ | 97 | $ | 50 | $ | 35 | ||||||
Changes
|
||||||||||||
Allowance
for SemCrude receivable
|
12 | 38 | - | |||||||||
Allowance
for Ecuador receivable
|
14 | 11 | 14 | |||||||||
Recovery
of Ecuador receivable
|
(46 | ) | - | - | ||||||||
Other
Changes
|
2 | - | - | |||||||||
Net
Changes Before Write-offs
|
(18 | ) | 49 | 14 | ||||||||
Write-off
of SemCrude receivable
|
(49 | ) | - | - | ||||||||
Other
Write-offs
|
1 | (2 | ) | 1 | ||||||||
Balance,
End of Period
|
$ | 31 | $ | 97 | $ | 50 |
December
31,
|
||||||||
2009
|
2008
|
|||||||
(millions)
|
||||||||
Materials
and Supplies
|
$ | 71 | $ | 92 | ||||
Crude
Oil
|
18 | 13 | ||||||
Total
|
$ | 89 | $ | 105 |
|
·
|
Commodity
Prices – Economic producibility of reserves and discounted cash flows is
now 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 Reserves Guidelines – Reserves may be classified as proved
undeveloped if there is a high degree of confidence that the quantities
will be recovered and they are scheduled to be drilled within the next five
years.
|
|
·
|
Reserves
Estimation Using New Technologies – Reserves may be estimated through the
use of reliable technology in addition to flow tests and production
history.
|
|
·
|
Reserves
Personnel and Estimation Process – Additional disclosure is required
regarding the qualifications of the chief technical person who oversees
the reserves estimation process. We are also 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 has expanded and focuses on
the marketable product rather than the method of
extraction.
|
|
·
|
describes
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; and
|
|
·
|
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.
|
|
·
|
$389
million related to Granite Wash, an onshore US
development;
|
|
·
|
$48
million related to Main Pass, our remaining operated Gulf of Mexico shelf
asset;
|
|
·
|
$44
million related to Paxton, an onshore US
development;
|
|
·
|
$23
million related to Raton, a deepwater Gulf of Mexico development;
and
|
|
·
|
$100
million related to our investment in
Ecuador.
|
|
·
|
$111
million related to various US proved oil and gas
properties;
|
|
·
|
$70
million related to our investment in
Ecuador;
|
|
·
|
$75
million related to various US unproved properties;
and
|
|
·
|
$38
million related to the Main Pass asset held for
sale.
|
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
|
||||||||||||||||
(millions)
|
||||||||||||||||||||
December
31, 2009
|
||||||||||||||||||||
Financial
Assets
|
||||||||||||||||||||
Mutual
Fund Investments
|
$ |
108
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
108
|
||||||||||
Commodity
Derivative Instruments
|
-
|
42
|
-
|
(28
|
) |
14
|
||||||||||||||
Financial
Liabilities
|
||||||||||||||||||||
Commodity
Derivative Instruments
|
-
|
(145
|
) |
-
|
28
|
(117
|
) | |||||||||||||
Patina
Deferred Compensation Liability
|
(168
|
) |
-
|
-
|
-
|
(168
|
) | |||||||||||||
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 settle
asset and liability positions with the same
counterparty.
|
Fair
Value Measurements Using
|
||||||||||||||||||
Description
|
Fair
Value
Measurement
(1)
|
Quoted
Prices in
Active
Markets
(Level
1)
|
Significant
Other
Observable
Inputs
(Level
2)
|
Unobservable
Inputs
(Level
3)
|
Total
Impairment
Loss
|
|||||||||||||
(millions)
|
||||||||||||||||||
Year
Ended December 31, 2009
|
||||||||||||||||||
Impaired
US Oil and Gas Properties
|
$ |
363
|
$ |
-
|
$ |
-
|
$ |
363
|
$ |
504
|
||||||||
Impaired
Investment in Ecuador
|
72
|
-
|
-
|
72
|
100
|
(1)
|
Amount
represents the fair values of the impaired properties as of the dates of
the assessments, March 31, 2009 and December 31, 2009. See Note
3. Asset Impairments.
|
Additional
Fair Value Disclosures
|
December
31,
|
||||||||||||||||
2009
|
2008
|
|||||||||||||||
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
|||||||||||||
(millions)
|
||||||||||||||||
Long-Term
Debt, Net of Unamortized Discount (1)
|
$ | 2,008 | $ | 2,279 | $ | 2,266 | $ | 2,172 |
(1)
|
Excludes
obligation under FPSO lease.
|
Variable
to Fixed Price Swaps
|
Collars
|
||||||||||||||||||||||
Production
Period
|
Index
|
Bbls
Per Day
|
Weighted
Average Fixed Price
|
Index
|
Bbls
Per Day
|
Weighted
Average Floor Price
|
Weighted
Average Ceiling Price
|
||||||||||||||||
2010
|
NYMEX
WTI
|
1,000 | $ | 78.70 |
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
|
2,000 | 79.38 | 21,500 | 62.30 | 75.09 | ||||||||||||||||||
2011
|
-
|
- | - |
NYMEX
WTI
|
6,000 | 79.00 | 87.42 |
Variable
to Fixed Price Swaps
|
Collars
|
||||||||||||||||||||||||
Production
Period
|
Index
|
MMBtu
Per Day
|
Weighted
Average Fixed Price
|
Index
|
MMBtu
Per Day
|
Weighted
Average Floor Price
|
Weighted
Average Ceiling Price
|
||||||||||||||||||
2010
|
NYMEX
HH
|
20,000 | $ | 6.10 |
NYMEX
HH (1)
|
210,000 | $ | 5.90 | $ | 6.73 | |||||||||||||||
2010
|
- | - | - |
IFERC
CIG (2)
|
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
|
||||||||||
Production
Period
|
Index
|
Index
Less Differential
|
MMBtu
Per Day
|
Weighted
Average Differential
|
||||||
2010
|
IFERC
CIG
|
NYMEX
HH
|
100,000
|
$ |
(1.60)
|
|||||
2011
|
IFERC
CIG
|
NYMEX
HH
|
110,000
|
(0.76)
|
Commodity
Derivative Instruments Not Designated as Hedging
Instruments
|
|||||||||||||||||||
Asset
Derivative Instruments
|
Liability
Derivative Instruments
|
||||||||||||||||||
December
31,
|
December
31,
|
||||||||||||||||||
2009
|
2008
|
2009
|
2008
|
||||||||||||||||
Balance
Sheet Location
|
Fair
Value
|
Balance
Sheet Location
|
Fair
Value
|
Balance
Sheet Location
|
Fair
Value
|
Balance
Sheet Location
|
Fair
Value
|
||||||||||||
(millions)
|
(millions)
|
||||||||||||||||||
Current
Assets
|
$ | 13 |
Current
Assets
|
$ | 437 |
Current
Liabilities
|
$ | 100 |
Current
Liabilities
|
$ | 23 | ||||||||
Noncurrent
Assets
|
1 |
Noncurrent
Assets
|
33 |
Noncurrent
Liabilities
|
17 |
Noncurrent
Liabilities
|
2 | ||||||||||||
Total
|
$ | 14 |
Total
|
$ | 470 |
Total
|
$ | 117 |
Total
|
$ | 25 |
Commodity
Derivative Instruments Not Designated as Hedging
Instruments
|
||||||||||
Amount
of (Gain) Loss on Derivative Instruments Recognized in
Income
|
||||||||||
Year
Ended December 31,
|
||||||||||
2009
|
2008
|
2007
|
||||||||
(millions)
|
||||||||||
Realized
Mark-to-Market (Gain) Loss
|
$ |
(496
|
) | $ |
82
|
$ |
-
|
|||
Unrealized
Mark-to-Market (Gain) Loss
|
606
|
(522
|
) |
-
|
||||||
Ineffectiveness
(Gain) Loss
|
-
|
-
|
(2
|
) | ||||||
Total
(Gain) Loss on Commodity Derivative Instruments
|
$ |
110
|
$ |
(440
|
) | $ |
(2
|
) |
Derivative
Instruments in Previously Designated Cash Flow Hedging
Relationships
|
||||||||||||||||||||||||
Amount
of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive
(Income) Loss
|
Amount
of (Gain) Loss on Derivative Instruments Reclassified from Accumulated
Other Comprehensive Loss
|
|||||||||||||||||||||||
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
|||||||||||||||||||
(millions)
|
||||||||||||||||||||||||
Commodity
Derivative Instruments (1)
|
||||||||||||||||||||||||
Crude
Oil
(2)
|
$ | - | $ | - | $ | 343 | $ | 58 | $ | 365 | $ | 223 | ||||||||||||
Natural
Gas (2)
|
- | - | (48 | ) | - | (34 | ) | (169 | ) | |||||||||||||||
Treasury
Rate Locks
|
- | (1 | ) | 1 | 1 | 1 | 1 | |||||||||||||||||
Total
|
$ | - | $ | (1 | ) | $ | 296 | $ | 59 | $ | 332 | $ | 55 |
(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 on derivative instruments reclassified from AOCL is
recognized in oil, gas and NGL sales within our consolidated statements of
operations.
|
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions)
|
||||||||||||
Capitalized
Exploratory Well Costs, Beginning of Period
|
$ | 501 | $ | 249 | $ | 80 | ||||||
Additions
to Capitalized Exploratory Well Costs Pending Determination of Proved
Reserves
|
136 | 253 | 182 | |||||||||
Reclassified
to Proved Oil and Gas Properties Based on Determination of Proved
Reserves
|
(198 | ) | - | (7 | ) | |||||||
Capitalized
Exploratory Well Costs Charged to Expense
|
(7 | ) | (1 | ) | (6 | ) | ||||||
Capitalized
Exploratory Well Costs, End of Period
|
$ | 432 | $ | 501 | $ | 249 |
December
31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions)
|
||||||||||||
Exploratory
Well Costs Capitalized for a Period of One Year or Less
|
$ | 158 | $ | 256 | $ | 187 | ||||||
Exploratory
Well Costs Capitalized for a Period Greater Than One Year After Completion
of Drilling
|
274 | 245 | 62 | |||||||||
Balance
at End of Period
|
$ | 432 | $ | 501 | $ | 249 | ||||||
Number
of Projects with Exploratory Well Costs That Have Been Capitalized for a
Period Greater Than One Year After Completion of Drilling
|
5 | 6 | 5 |
Suspended
Since
|
||||||||||||||||
Total
|
2008
|
2007
|
2006
& Prior
|
|||||||||||||
(millions)
|
||||||||||||||||
Project
|
||||||||||||||||
Blocks
O and I (West Africa)
|
$ | 172 | $ | 62 | $ | 96 | $ | 14 | ||||||||
Gunflint
(Deepwater Gulf of Mexico)
|
49 | 49 | - | - | ||||||||||||
Redrock
(Deepwater Gulf of Mexico)
|
17 | - | - | 17 | ||||||||||||
Flyndre
(North Sea)
|
15 | - | 12 | 3 | ||||||||||||
Selkirk
(North Sea)
|
21 | - | 21 | - | ||||||||||||
Total
Exploratory Well Costs Capitalized for a Period Greater Than One Year
After Completion of Drilling
|
$ | 274 | $ | 111 | $ | 129 | $ | 34 |
December
31,
|
||||||||||||||||
2009
|
2008
|
|||||||||||||||
Debt
|
Interest
Rate
|
Debt
|
Interest
Rate
|
|||||||||||||
(millions,
except percentages)
|
||||||||||||||||
Credit
Facility (1)
|
$ | 382 | 0.54 | % | $ | 1,606 | 0.80 | % | ||||||||
5¼%
Senior Notes, due April 15, 2014
|
200 | 5.25 | % | 200 | 5.25 | % | ||||||||||
8¼%
Senior Notes, due March 1, 2019
|
1,000 | 8.25 | % | - | - | |||||||||||
7¼%
Notes, due October 15, 2023
|
100 | 7.25 | % | 100 | 7.25 | % | ||||||||||
8%
Senior Notes, due April 1, 2027
|
250 | 8.00 | % | 250 | 8.00 | % | ||||||||||
7¼%
Senior Debentures, due August 1, 2097
|
84 | 7.25 | % | 89 | 7.25 | % | ||||||||||
Obligation
Under FPSO Lease (2)
|
29 | - | - | - | ||||||||||||
Long-term
Debt
|
2,045 | 2,245 | ||||||||||||||
Installment
Payment, due May 11, 2009
|
- | - | 25 | 4.18 | % | |||||||||||
Total
Debt
|
2,045 | 2,270 | ||||||||||||||
Unamortized
Discount
|
(8 | ) | (4 | ) | ||||||||||||
Total
Debt, Net of Discount
|
$ | 2,037 | $ | 2,266 |
(1)
|
We
expect to use the credit facility to fund our planned $494 million
acquisition of US Rocky Mountain assets in the first quarter 2010. See
Note 4. Acquisitions and Divestitures – Pending Asset
Acquisition.
|
(2)
|
Amount
reported is based on percentage of FPSO construction activities completed
as of December 31, 2009 and therefore does not reflect future minimum
lease obligations. See Obligation Under FPSO
Lease below.
|
As
of December 31, 2009
|
||||
(millions)
|
||||
2010
|
$ | - | ||
2011
|
- | |||
2012
|
382 | |||
2013
|
- | |||
2014
|
200 | |||
Thereafter
|
1,434 | |||
Total
|
$ | 2,016 |
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions)
|
||||||||||||
Domestic
|
$ | (808 | ) | $ | 1,032 | $ | 480 | |||||
Foreign
|
544 | 1,029 | 888 | |||||||||
Total
|
$ | (264 | ) | $ | 2,061 | $ | 1,368 |
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions)
|
||||||||||||
Current
Taxes
|
||||||||||||
Federal
|
$ | 45 | $ | 45 | $ | 6 | ||||||
State
|
1 | 1 | 1 | |||||||||
Foreign
|
117 | 306 | 125 | |||||||||
Total
Current
|
163 | 352 | 132 | |||||||||
Deferred
Taxes
|
||||||||||||
Federal
|
(320 | ) | 363 | 186 | ||||||||
State
|
(5 | ) | 4 | 6 | ||||||||
Foreign
|
29 | (8 | ) | 100 | ||||||||
Total
Deferred
|
(296 | ) | 359 | 292 | ||||||||
Total
Income Tax Provision (Benefit)
|
$ | (133 | ) | $ | 711 | $ | 424 |
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(percentages)
|
||||||||||||
Federal
Statutory Rate
|
35.0 | 35.0 | 35.0 | |||||||||
Effect
of
|
||||||||||||
Earnings
of Equity Method Investees
|
11.3 | (2.9 | ) | (5.4 | ) | |||||||
State
Taxes, Net of Federal Benefit
|
1.5 | 0.2 | 0.5 | |||||||||
Difference
Between US and Foreign Rates
|
(1.4 | ) | 1.8 | 1.6 | ||||||||
Percentage
Depletion in Excess of Basis
|
4.5 | - | - | |||||||||
Other,
Net
|
(0.5 | ) | 0.4 | (0.7 | ) | |||||||
Effective
Rate
|
50.4 | 34.5 | 31.0 |
December
31,
|
||||||||
2009
|
2008
|
|||||||
(millions)
|
||||||||
Deferred
Tax Assets
|
||||||||
Loss
Carryforwards
|
$ | 49 | $ | 36 | ||||
Ecuador
Investment
|
20 | 18 | ||||||
Accrued
Expenses
|
17 | 32 | ||||||
Allowance
for Doubtful Accounts
|
6 | 20 | ||||||
Net
Pension Obligation
|
34 | 36 | ||||||
Postretirement
Benefits
|
34 | 31 | ||||||
Deferred
Compensation
|
73 | 63 | ||||||
Foreign
Tax Credits
|
28 | 51 | ||||||
Commodity
Derivative Assets
|
54 | - | ||||||
Other
|
35 | 27 | ||||||
Total
Deferred Tax Assets
|
350 | 314 | ||||||
Valuation
Allowance - Foreign Loss Carryforwards
|
(45 | ) | (35 | ) | ||||
Valuation
Allowance - Foreign Tax Credits
|
(28 | ) | (51 | ) | ||||
Valuation
Allowance - Ecuador Investment
|
(20 | ) | (18 | ) | ||||
Net
Deferred Tax Assets
|
257 | 210 | ||||||
Deferred
Tax Liabilities
|
||||||||
Property,
Plant and Equipment, Principally Due to Differences in Depreciation,
Amortization, Lease Impairment and Abandonments
|
(2,302 | ) | (2,388 | ) | ||||
Commodity
Derivative Assets
|
- | (138 | ) | |||||
Total
Deferred Tax Liability
|
(2,302 | ) | (2,526 | ) | ||||
Net
Deferred Tax Liability
|
$ | (2,045 | ) | $ | (2,316 | ) |
December
31,
|
||||||||
2009
|
2008
|
|||||||
(millions)
|
||||||||
Deferred
Income Tax Asset
|
$ | 32 | $ | - | ||||
Deferred
Income Tax Liability - Current
|
(1 | ) | (142 | ) | ||||
Deferred
Income Tax Liability - Noncurrent
|
(2,076 | ) | (2,174 | ) | ||||
Net
Deferred Tax Liability
|
$ | (2,045 | ) | $ | (2,316 | ) |
Year
Ended December 31,
|
||||||||
2009
|
2008
|
|||||||
(in
millions)
|
||||||||
Asset
Retirement Obligations, Beginning of Period
|
$ | 211 | $ | 144 | ||||
Liabilities
Incurred in Current Period
|
22 | 15 | ||||||
Liabilities
Settled in Current Period
|
(36 | ) | (33 | ) | ||||
Revisions
|
21 | 75 | ||||||
Accretion
Expense
|
14 | 10 | ||||||
Asset
Retirement Obligations, End of Period
|
$ | 232 | $ | 211 |
|
·
|
45%
interest in Atlantic Methanol Production Company, LLC (AMPCO), which owns
and operates a methanol plant and related facilities in Equatorial Guinea;
and
|
|
·
|
28%
interest in Alba Plant LLC (Alba Plant), which owns and operates a
liquefied petroleum gas processing plant in Equatorial
Guinea.
|
December
31,
|
||||||||
2009
|
2008
|
|||||||
(millions)
|
||||||||
Equity
Method Investments
|
||||||||
AMPCO
|
$ | 180 | $ | 190 | ||||
Alba
Plant
|
111 | 106 | ||||||
Other
|
12 | 15 | ||||||
Total
Equity Method Investments
|
$ | 303 | $ | 311 |
December
31,
|
||||||||||||
2009
|
2008
|
|||||||||||
(millions)
|
||||||||||||
Balance
Sheet Information
|
||||||||||||
Current
Assets
|
$ | 269 | $ | 283 | ||||||||
Noncurrent
Assets
|
751 | 783 | ||||||||||
Current
Liabilities
|
187 | 248 | ||||||||||
Noncurrent
Liabilities
|
59 | 43 | ||||||||||
Year
Ended December 31,
|
||||||||||||
2009
|
2008 | 2007 | ||||||||||
(millions)
|
||||||||||||
Statements
of Operations Information
|
||||||||||||
Operating
Revenues
|
$ | 632 | $ | 1,022 | $ | 934 | ||||||
Operating
Expenses
|
264 | 301 | 270 | |||||||||
Operating
Income
|
368 | 721 | 664 | |||||||||
Other
Income, Net
|
(13 | ) | (14 | ) | (14 | ) | ||||||
Income
Before Income Taxes
|
381 | 735 | 678 | |||||||||
Income
Tax Provision (1)
|
95 | 183 | 44 | |||||||||
Net
Income
|
$ | 286 | $ | 552 | $ | 634 |
(1)
|
The
increase in income tax expense in 2008 is due to the expiration of the
Alba Plant tax holiday.
|
Retirement
and Restoration Plans
|
Medical
and Life Plans
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(millions)
|
||||||||||||||||
Change
in Benefit Obligation
|
||||||||||||||||
Benefit
Obligation at Beginning of Year
|
$ | 194 | $ | 188 | $ | 22 | $ | 22 | ||||||||
Service
Cost
|
12 | 12 | 2 | 2 | ||||||||||||
Interest
Cost
|
11 | 12 | 1 | 1 | ||||||||||||
Benefits
Paid
|
(13 | ) | (17 | ) | (1 | ) | (1 | ) | ||||||||
Plan
Amendments (1)
|
- | - | (2 | ) | - | |||||||||||
Actuarial
(Gain) Loss
|
24 | (1 | ) | 1 | (2 | ) | ||||||||||
Benefit
Obligation at End of Year
|
228 | 194 | 23 | 22 | ||||||||||||
Change
in Plan Assets
|
||||||||||||||||
Fair
Value of Plan Assets at Beginning of Year
|
132 | 155 | - | - | ||||||||||||
Actual
Return on Plan Assets
|
33 | (43 | ) | - | - | |||||||||||
Employer
Contributions
|
20 | 37 | 1 | 1 | ||||||||||||
Benefits
Paid
|
(13 | ) | (17 | ) | (1 | ) | (1 | ) | ||||||||
Fair
Value of Plan Assets at End of Year
|
172 | 132 | - | - | ||||||||||||
Funded
Status
|
||||||||||||||||
Funded
Status at End of Year
|
(56 | ) | (62 | ) | (23 | ) | (22 | ) | ||||||||
Net
Amount Recognized in Consolidated Balance Sheets
|
(56 | ) | (62 | ) | (23 | ) | (22 | ) | ||||||||
Amounts
Recognized in Consolidated Balance Sheets Consist of
|
||||||||||||||||
Current
Liabilities
|
(2 | ) | (2 | ) | (1 | ) | (1 | ) | ||||||||
Noncurrent
Liabilities
|
(54 | ) | (60 | ) | (22 | ) | (21 | ) | ||||||||
Net
Amount Recognized in Consolidated Balance Sheets
|
(56 | ) | (62 | ) | (23 | ) | (22 | ) | ||||||||
Amounts
Not Yet Reflected in Net Periodic Benefit Cost and Included in
AOCL
|
||||||||||||||||
Prior
Service (Cost) Credit
|
(3 | ) | (3 | ) | 7 | 5 | ||||||||||
Accumulated
Loss
|
(88 | ) | (86 | ) | (11 | ) | (10 | ) | ||||||||
AOCL
|
(91 | ) | (89 | ) | (4 | ) | (5 | ) | ||||||||
Cumulative
Employer Contributions in Excess of Net Periodic Benefit
Cost
|
35 | 27 | (19 | ) | (17 | ) | ||||||||||
Net
Amount Recognized in Consolidated Balance Sheets
|
$ | (56 | ) | $ | (62 | ) | $ | (23 | ) | $ | (22 | ) |
Retirement
and Restoration Plans
|
Medical
and Life Plans
|
|||||||||||||||||||||||
Year
Ended December 31,
|
Year
Ended December 31,
|
|||||||||||||||||||||||
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
|||||||||||||||||||
(millions)
|
||||||||||||||||||||||||
Components
of Net Periodic Benefit Cost
|
||||||||||||||||||||||||
Service
Cost
|
$ | 12 | $ | 12 | $ | 12 | $ | 2 | $ | 2 | $ | 2 | ||||||||||||
Interest
Cost
|
11 | 12 | 10 | 1 | 1 | 1 | ||||||||||||||||||
Expected
Return on Plan Assets
|
(14 | ) | (12 | ) | (11 | ) | - | - | - | |||||||||||||||
Amortization
of Prior Service (Credit) Cost
|
- | - | - | (1 | ) | (1 | ) | (1 | ) | |||||||||||||||
Amortization
of Net Loss
|
3 | 2 | 3 | 1 | 1 | 1 | ||||||||||||||||||
Net
Periodic Benefit Cost
|
$ | 12 | $ | 14 | $ | 14 | $ | 3 | $ | 3 | $ | 3 | ||||||||||||
Other
Changes Recognized in AOCL
|
||||||||||||||||||||||||
Prior
Service Cost Arising During Period
|
$ | - | $ | - | $ | 8 | $ | (2 | ) | $ | - | $ | - | |||||||||||
Net
Loss (Gain) Arising During Period
|
5 | 53 | (13 | ) | 1 | (3 | ) | (3 | ) | |||||||||||||||
Amortization
of Prior Service Credit
|
- | - | - | 1 | 1 | 1 | ||||||||||||||||||
Amortization
of Net Loss
|
(3 | ) | (2 | ) | (3 | ) | (1 | ) | (1 | ) | (1 | ) | ||||||||||||
Total
Recognized in AOCL
|
$ | 2 | $ | 51 | $ | (8 | ) | $ | (1 | ) | $ | (3 | ) | $ | (3 | ) | ||||||||
Expected
Amortizations for Next Fiscal Year
|
||||||||||||||||||||||||
Amortization
of Prior Service Cost (Credit)
|
$ | - | $ | - | $ | - | $ | (1 | ) | $ | (1 | ) | $ | (1 | ) | |||||||||
Amortization
of Net Loss
|
5 | 2 | 2 | 1 | 1 | 1 | ||||||||||||||||||
Weighted-Average Assumptions Used to Determine Benefit Obligations | ||||||||||||||||||||||||
Discount
Rate (1)
|
6.00 | % | 6.00% / 6.25 | % | 6.50 | % | 5.50 | % | 6.25 | % | 6.25 | % | ||||||||||||
Rate
of Compensation Increase
|
5.00 | % | 5.00 | % | 5.00 | % | - | - | - | |||||||||||||||
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs | ||||||||||||||||||||||||
Discount Rate (1)
|
6.00% / 6.25 | % | 6.50 | % | 5.75 | % | 6.25 | % | 6.25 | % | 5.75 | % | ||||||||||||
Expected
Long-Term Rate of Return on Plan Assets
|
8.00 | % | 8.25 | % | 8.25 | % | - | - | - | |||||||||||||||
Rate
of Compensation Increase
|
5.00 | % | 5.00 | % | 5.00 | % | - | - | - |
(1)
|
The
discount rates used to determine benefit obligations at December 31, 2008
and net periodic benefit costs for the year ended December 31, 2009 were
6.00% for the retirement plan and 6.25% for the restoration
plan.
|
December
31,
|
|||||||
2009
|
2008
|
||||||
(millions)
|
|||||||
Accumulated
Benefit Obligation
|
$ |
197
|
$ |
169
|
|||
Information
for Pension Plans With Projected Benefit Obligations in Excess of Plan
Assets
|
|||||||
Projected
Benefit Obligation
|
228
|
194
|
|||||
Fair
Value of Plan Assets
|
172
|
132
|
|||||
Information
for Pension Plans With Accumulated Benefit Obligations in Excess of Plan
Assets
|
|||||||
Accumulated
Benefit Obligation
|
31
|
169
|
|||||
Fair
Value of Plan Assets
|
-
|
132
|
December
31,
|
||||||||
2009
|
2008
|
|||||||
Health
Care Cost Trend Rate Assumed for Next Year
|
8.00 | % | 8.00 | % | ||||
Rate
to Which the Cost Trend Rate is Assumed to Decline (Ultimate Trend
Rate)
|
4.50 | % | 5.00 | % | ||||
Year
Rate Reaches Ultimate Trend Rate
|
2030 | 2012 |
1%
Increase
|
1%
Decrease
|
|||||||
(millions)
|
||||||||
Effect
on Total Service and Interest Cost Components for 2009
|
$ | - | $ | - | ||||
Effect
on Year-End 2009 Postretirement Benefit Obligation
|
3 | (2 | ) |
Target
Allocation
|
Plan
Assets
|
|||||||||||
2010
|
2009
|
2008
|
||||||||||
Asset
Category
|
||||||||||||
Equity
Securities
|
70 | % | 73 | % | 65 | % | ||||||
Fixed
Income
|
30 | % | 27 | % | 35 | % | ||||||
Total
|
100 | % | 100 | % | 100 | % |
Fair
Value Measurements at December 31, 2009
|
|||||||||||||
Total
|
Quoted
Prices in Active Markets for Identical Assets (Level
1)
|
Significant
Observable Inputs (Level 2)
|
Significant
Unobservable Inputs (Level 3)
|
||||||||||
(millions)
|
|||||||||||||
Asset
Category
|
|||||||||||||
Federal
Money Market Funds
|
$ |
2
|
$ |
2
|
$ |
-
|
$ |
-
|
|||||
Mutual
Funds
|
|||||||||||||
Equity
(Common Stocks)
|
76
|
76
|
-
|
-
|
|||||||||
Fixed
Income
|
47
|
47
|
-
|
-
|
|||||||||
Common
Collective Trust Funds
|
47
|
-
|
47
|
-
|
|||||||||
Total
|
$ |
172
|
$ |
125
|
$ |
47
|
$ |
-
|
Retirement
and Restoration Plans
|
Medical
and Life Plans
|
||||||
(millions)
|
|||||||
2010
|
$ |
14
|
$ |
1
|
|||
2011
|
18
|
1
|
|||||
2012
|
20
|
1
|
|||||
2013
|
19
|
2
|
|||||
2014
|
21
|
2
|
|||||
Years
2015 to 2019
|
120
|
11
|
December
31,
|
||||||||
2009
|
2008
|
|||||||
(millions,
except share amounts)
|
||||||||
Rabbi
Trust Assets
|
||||||||
Mutual
Fund Investments
|
$ | 93 | $ | 71 | ||||
Noble
Energy Common Stock (at Fair Value) (1)
|
75 | 52 | ||||||
Total
Rabbi Trust Assets
|
168 | 123 | ||||||
Liability
Under Patina Deferred Compensation Plan
|
$ | 168 | $ | 123 | ||||
Number
of Shares of Noble Energy Common Stock Held by Rabbi Trust
|
1,049,140 | 1,051,032 |
(1)
|
Shares
of our common stock are accounted for as treasury stock and recorded at
cost in the consolidated balance
sheets.
|
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions)
|
||||||||||||
Stock-Based
Compensation Expense Included in
|
||||||||||||
General
and Administrative Expense
|
$ | 36 | $ | 38 | $ | 25 | ||||||
Exploration
Expense and Other
|
13 | 1 | 2 | |||||||||
Total
Stock-Based Compensation Expense
|
$ | 49 | $ | 39 | $ | 27 | ||||||
Tax
Benefit Recognized
|
$ | (17 | ) | $ | (15 | ) | $ | (10 | ) |
|
·
|
Expected term
The expected term represents the period of time that options
granted are expected to be outstanding, which is the grant date to the
date of expected exercise or other expected settlement for options
granted. The hypothetical midpoint scenario we use considers our actual
exercise and post-vesting cancellation history and expectations for future
periods, which assumes that all vested, outstanding options are settled
halfway between their vesting date and their expiration
date.
|
|
·
|
Expected
volatility The expected volatility represents the
extent to which our stock price is expected to fluctuate between the grant
date and the expected term of the award. We use the historical volatility
of our common stock for a period equal to the expected term of the option
prior to the date of grant. We believe that historical volatility produces
an estimate that is representative of our expectations about the future
volatility of our common stock over the expected
term.
|
|
·
|
Risk-free rate
The risk-free rate is the implied yield available on US Treasury
securities with a remaining term equal to the expected term of the option.
We base our risk-free rate on a weighting of five and seven year US
Treasury securities as of the date of grant to arrive at an approximated
5.5-year risk free rate of return.
|
|
·
|
Dividend yield
The dividend yield represents the value of our stock’s annualized
dividend as compared to our stock’s average price for the three-year
period ended prior to the date of grant. It is calculated by dividing one
full year of our expected dividends by our average stock price over the
three-year period ended prior to the date of
grant.
|
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(weighted
averages)
|
||||||||||||
Expected
Term (in Years)
|
5.5 | 5.5 | 5.5 | |||||||||
Expected
Volatility
|
43.0 | % | 27.7 | % | 29.6 | % | ||||||
Risk-Free
Rate
|
2.0 | % | 2.9 | % | 4.7 | % | ||||||
Expected
Dividend Yield
|
1.2 | % | 1.0 | % | 0.6 | % |
Options
|
Weighted
Average Exercise Price
|
Weighted
Average Remaining Contractual Term
|
Aggregate
Intrinsic Value
|
|||||||||||||
(per
share)
|
(in
years)
|
(in
millions)
|
||||||||||||||
Outstanding
at December 31, 2008
|
6,082,375 | $ | 41.41 | |||||||||||||
Granted
|
1,574,252 | 50.99 | ||||||||||||||
Exercised
|
(704,209 | ) | 25.01 | |||||||||||||
Forfeited
|
(132,127 | ) | 56.90 | |||||||||||||
Outstanding
at December 31, 2009
|
6,820,291 | $ | 45.01 | 6.0 | $ | 182 | ||||||||||
Exercisable
at December 31, 2009
|
4,245,616 | $ | 37.62 | 4.4 | $ | 144 |
Shares
Subject to Service Conditions
|
Weighted
Average Grant Date Fair Value
|
Shares
Subject to Market Conditions
|
Weighted
Average Grant Date Fair Value
|
|||||||||||||
(per
share)
|
(per
share)
|
|||||||||||||||
Outstanding
at December 31, 2008
|
891,027 | $ | 62.91 | 68,493 | $ | 35.40 | ||||||||||
Awarded
|
612,226 | 51.63 | - | - | ||||||||||||
Vested
|
(19,245 | ) | 64.47 | (68,493 | ) | 35.40 | ||||||||||
Forfeited
|
(62,808 | ) | 58.18 | - | - | |||||||||||
Outstanding
at December 31, 2009
|
1,421,200 | $ | 58.31 | - | $ | - |
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions,
except per share amounts)
|
||||||||||||
Net
Income (Loss)
|
$ | (131 | ) | $ | 1,350 | $ | 944 | |||||
Earnings
Adjustment from Assumed Conversion of Dilutive Shares of Common Stock in
Rabbi Trust (1)
|
- | (20 | ) | - | ||||||||
Net
Income (Loss) Used for Diluted Earnings Per Share
Calculation
|
$ | (131 | ) | $ | 1,330 | $ | 944 | |||||
Weighted
Average Number of Shares Outstanding, Basic
|
173 | 173 | 171 | |||||||||
Incremental
Shares from Assumed Conversion of
|
||||||||||||
Dilutive
Options, Restricted Stock and Shares of Common Stock in Rabbi
Trust
|
- | 3 | 2 | |||||||||
Weighted
Average Number of Shares Outstanding, Diluted
|
173 | 176 | 173 | |||||||||
Earnings
(Loss) Per Share, Basic
|
$ | (0.75 | ) | $ | 7.83 | $ | 5.52 | |||||
Earnings
(Loss) Per Share, Diluted
|
(0.75 | ) | 7.58 | 5.45 |
(1)
|
The
diluted earnings per share calculation for 2008 includes a decrease to net
income of $20 million (net of tax) related to a deferred compensation gain
from shares of our common stock held in a rabbi trust. When dilutive, the
deferred compensation gain or loss (net of tax) is excluded from net
income while the shares of our common stock held in the rabbi trust are
included in the outstanding diluted share
count.
|
Consolidated
|
United
States
|
West
Africa
|
Eastern
Mediter-ranean
|
North
Sea
|
Other
Int'l, Corporate, Marketing
|
||||||||||||||
(millions)
|
|||||||||||||||||||
Year
Ended December 31, 2009
|
|||||||||||||||||||
Revenues
from Third Parties
|
$ | 2,287 | $ | 1,323 | $ | 340 | $ | 144 | $ | 153 | $ | 327 | |||||||
Reclassification
from AOCL (1)
|
(58 | ) | (29 | ) | (29 | ) | - | - | - | ||||||||||
Intersegment
Revenue
|
- | 161 | - | - | - | (161 | ) | ||||||||||||
Income
from Equity Method Investees
|
84 | - | 84 | - | - | - | |||||||||||||
Total
Revenues (2)
|
2,313 | 1,455 | 395 | 144 | 153 | 166 | |||||||||||||
DD&A
|
816 | 689 | 38 | 20 | 34 | 35 | |||||||||||||
Asset
Impairments
|
604 | 504 | - | - | - | 100 | |||||||||||||
Loss
on Commodity Derivative Instruments
|
110 | 73 | 37 | - | - | - | |||||||||||||
Income
(Loss) Before Income Taxes
|
(264 | ) | (287 | ) | 257 | 98 | 62 | (394 | ) | ||||||||||
Equity
Method Investments
|
$ | 303 | $ | - | 303 | $ | - | $ | - | $ | - | ||||||||
Additions
to Long-Lived Assets
|
1,282 | 911 | 124 | 103 | 103 | 41 | |||||||||||||
Total
Assets at December 31, 2009 (3)
|
11,807 | 8,669 | 1,731 | 486 | 635 | 286 | |||||||||||||
Year
Ended December 31, 2008
|
|||||||||||||||||||
Revenues
from Third Parties
|
$ | 4,058 | $ | 2,315 | $ | 541 | $ | 157 | $ | 410 | $ | 635 | |||||||
Reclassification
from AOCL (1)
|
(331 | ) | (290 | ) | (41 | ) | - | - | - | ||||||||||
Intersegment
Revenue
|
- | 434 | - | - | - | (434 | ) | ||||||||||||
Income
from Equity Method Investees
|
174 | - | 174 | - | - | - | |||||||||||||
Total
Revenues (2)
|
3,901 | 2,459 | 674 | 157 | 410 | 201 | |||||||||||||
DD&A
|
791 | 646 | 34 | 24 | 55 | 32 | |||||||||||||
Asset
Impairments
|
294 | 224 | - | - | - | 70 | |||||||||||||
Gain
on Commodity Derivative Instruments
|
(440 | ) | (363 | ) | (77 | ) | - | - | - | ||||||||||
Income
(Loss) Before Income Taxes
|
2,061 | 1,333 | 689 | 122 | 284 | (367 | ) | ||||||||||||
Equity
Method Investments
|
$ | 311 | $ | - | $ | 311 | $ | - | $ | - | $ | - | |||||||
Additions
to Long-Lived Assets
|
2,179 | 1,842 | 143 | 39 | 94 | 61 | |||||||||||||
Total
Assets at December 31, 2008 (3)
|
12,384 | 9,212 | 1,614 | 366 | 775 | 417 | |||||||||||||
Year
Ended December 31, 2007
|
|||||||||||||||||||
Revenues
from Third Parties
|
$ | 3,115 | $ | 1,651 | $ | 418 | $ | 113 | $ | 364 | $ | 569 | |||||||
Reclassification
from AOCL (1)
|
(54 | ) | (42 | ) | (12 | ) | - | - | - | ||||||||||
Intersegment
Revenue
|
- | 343 | - | - | - | (343 | ) | ||||||||||||
Income
from Equity Method Investees
|
211 | - | 211 | - | - | - | |||||||||||||
Total
Revenues (2)
|
3,272 | 1,952 | 617 | 113 | 364 | 226 | |||||||||||||
DD&A
|
736 | 580 | 25 | 18 | 81 | 32 | |||||||||||||
Loss
on Involuntary Conversion of Assets
|
51 | 51 | - | - | - | - | |||||||||||||
Income
(Loss) Before Income Taxes
|
1,368 | 810 | 517 | 86 | 221 | (266 | ) | ||||||||||||
Equity
Method Investments
|
$ | 357 | $ | - | $ | 357 | $ | - | $ | - | $ | - | |||||||
Additions
to Long-Lived Assets
|
1,623 | 1,285 | 151 | 26 | 83 | 78 | |||||||||||||
Total
Assets at December 31, 2007 (3)
|
10,831 | 7,918 | 1,355 | 268 | 562 | 728 |
(1)
|
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.
|
(2)
|
Revenues
from third parties for all foreign countries, in total, were $791 million
in 2009, $1.3 billion in 2008, and $1.1 billion
2007.
|
(3)
|
The US reporting
unit includes goodwill of $758 million at December 31, 2009, $759 million
at December 31, 2008, and $761 million at December 31, 2007.
Long-lived assets located in all foreign countries, in total, were
$1.6 billion, $1.5 billion, and $1.4 billion at December 31, 2009, 2008,
and 2007, respectively.
|
Year
Ended December 31,
|
||||||||
2009
|
2008
|
|||||||
Common
Stock Shares Issued
|
||||||||
Shares,
Beginning of Period
|
192,296,764 | 190,814,309 | ||||||
Exercise
of Common Stock Options
|
704,209 | 1,080,116 | ||||||
Restricted
Stock Awards, Net of Forfeitures
|
549,418 | 402,339 | ||||||
Shares,
End of Period
|
193,550,391 | 192,296,764 | ||||||
Treasury
Stock
|
||||||||
Shares,
Beginning of Period
|
18,563,409 | 18,580,865 | ||||||
Shares
Received From Employees in Payment of Withholding Taxes Due on Vesting of
Shares of Restricted Stock
|
20,784 | 32,544 | ||||||
Rabbi
Trust Shares Sold
|
(1,892 | ) | (50,000 | ) | ||||
Shares,
End of Period
|
18,582,301 | 18,563,409 |
Accumulated
Other Comprehensive Loss
|
|||||||||||
Oil
and Gas Cash Flow Hedges
|
Pension-Related
and Other
|
Total
|
|||||||||
(millions)
|
|||||||||||
December
31, 2006
|
|||||||||||
Cash
Flow Hedges
|
$ |
(104
|
) | $ |
(36
|
) | $ |
(140
|
) | ||
Realized
Amounts Reclassified Into Earnings
|
33
|
3
|
36
|
||||||||
Unrealized
Change in Fair Value
|
(184
|
) |
(1
|
) |
(185
|
) | |||||
Net
Change in Other
|
-
|
5
|
5
|
||||||||
December
31, 2007
|
(255
|
) |
(29
|
) |
(284
|
) | |||||
Cash
Flow Hedges
|
|||||||||||
Realized
Amounts Reclassified Into Earnings
|
207
|
3
|
210
|
||||||||
Unrealized
Change in Fair Value
|
-
|
(4
|
) |
(4
|
) | ||||||
Net
Change in Other
|
-
|
(32
|
) |
(32
|
) | ||||||
December
31, 2008
|
(48
|
) |
(62
|
) |
(110
|
) | |||||
Cash
Flow Hedges
|
|||||||||||
Realized
Amounts Reclassified Into Earnings
|
36
|
3
|
39
|
||||||||
Net
Change in Other
|
-
|
(4
|
) |
(4
|
) | ||||||
December
31, 2009
|
$ |
(12
|
) | $ |
(63
|
) | $ |
(75
|
) |
Drilling,
Equipment, and Purchase Obligations
|
Throughput
Agreement
|
Transportation
and Gathering
|
Operating
Lease Obligations
|
FPSO
Lease Obligation (1)
|
Total
|
||||||||||||||
(millions)
|
|||||||||||||||||||
2010
|
$ |
671
|
$ |
19
|
$ |
11
|
$ |
12
|
$ |
-
|
$ |
713
|
|||||||
2011
|
336
|
19
|
10
|
10
|
-
|
375
|
|||||||||||||
2012
|
27
|
19
|
7
|
9
|
35
|
97
|
|||||||||||||
2013
|
-
|
19
|
6
|
10
|
69
|
104
|
|||||||||||||
2014
|
-
|
5
|
3
|
11
|
69
|
88
|
|||||||||||||
2015
and Thereafter
|
-
|
-
|
3
|
31
|
295
|
329
|
|||||||||||||
Total
|
$ |
1,034
|
$ |
81
|
$ |
40
|
$ |
83
|
$ |
468
|
$ |
1,706
|
(1)
|
Annual
lease payments, net to our interest, exclude regular maintenance and
operational costs, and will begin when the FPSO initiates producing
operations. These payments are also subject to change based on change
orders implemented during the construction period, final accounting
treatment and other factors. See Note 8.
Debt.
|
Crude
Oil, Condensate and NGLs (MMBbls)
|
||||||||||||||||
United
States
|
Equatorial
Guinea
|
Other
Int'l (1)
|
Total
|
|||||||||||||
Proved
Reserves as of:
|
||||||||||||||||
December
31, 2006
|
170 | 90 | 36 | 296 | ||||||||||||
Revisions
of Previous Estimates (2)
|
28 | - | 1 | 29 | ||||||||||||
Extensions,
Discoveries and Other Additions (3)
|
27 | - | 10 | 37 | ||||||||||||
Purchase
of Minerals in Place
|
- | - | - | - | ||||||||||||
Sale
of Minerals in Place
|
(2 | ) | - | - | (2 | ) | ||||||||||
Production
(4)
|
(16 | ) | (8 | ) | (7 | ) | (31 | ) | ||||||||
December
31, 2007
|
207 | 82 | 40 | 329 | ||||||||||||
Revisions
of Previous Estimates (2)
|
(10 | ) | 1 | - | (9 | ) | ||||||||||
Extensions,
Discoveries and Other Additions (3)
|
16 | - | 11 | 27 | ||||||||||||
Purchase
of Minerals in Place
|
3 | - | - | 3 | ||||||||||||
Sale
of Minerals in Place (5)
|
- | - | (7 | ) | (7 | ) | ||||||||||
Production
(4)
|
(18 | ) | (8 | ) | (6 | ) | (32 | ) | ||||||||
December
31, 2008
|
198 | 75 | 38 | 311 | ||||||||||||
Revisions
of Previous Estimates (2)
|
(5 | ) | (1 | ) | - | (6 | ) | |||||||||
Extensions,
Discoveries and Other Additions (3)
|
32 | 26 | 1 | 59 | ||||||||||||
Purchase
of Minerals in Place
|
1 | - | - | 1 | ||||||||||||
Sale
of Minerals in Place
|
- | - | - | - | ||||||||||||
Production
(4)
|
(17 | ) | (8 | ) | (4 | ) | (29 | ) | ||||||||
December
31, 2009
|
209 | 92 | 35 | 336 | ||||||||||||
Proved
Developed Reserves as of:
|
||||||||||||||||
December
31, 2006
|
115 | 90 | 35 | 240 | ||||||||||||
December
31, 2007
|
129 | 71 | 29 | 229 | ||||||||||||
December
31, 2008
|
121 | 57 | 21 | 199 | ||||||||||||
December
31, 2009
|
122 | 49 | 23 | 194 | ||||||||||||
Proved
Undeveloped Reserves as of:
|
||||||||||||||||
December
31, 2006
|
55 | - | 1 | 56 | ||||||||||||
December
31, 2007
|
78 | 11 | 11 | 100 | ||||||||||||
December
31, 2008
|
77 | 18 | 17 | 112 | ||||||||||||
December
31, 2009
|
87 | 43 | 12 | 142 |
(1)
|
Other
International includes the North Sea, China and Argentina. We sold our
Argentina assets in February 2008.
|
(2)
|
The
2007 positive revisions within the US are primarily due to 29 MMBbl of
NGLs, previously recorded in proved natural gas reserves, being reflected
in proved oil reserves, partially offset by negative revisions within the
US Southern region related to less than expected well performance. The
2008 negative revisions within the US are primarily due to lower year-end
prices (28 MMBbl), partially offset by the recording of NGLs which had
previously been recorded in proved natural gas reserves. The 2009 negative
revisions within the US are primarily
due to performance revisions, the majority of which related to the
abandonment of Main Pass (10 MMBbl) and reclassifications of proved
undeveloped reserves to probable reserves as a result of the SEC’s new
five year development rule (5 MMBbl), partially offset by higher year-end
prices (10 MMBbl).
|
(3)
|
The
2007 increase in proved reserves includes 17 MMBbl in the US Wattenberg
field, primarily due to infill drilling activities, 8 MMBbl in the
deepwater Gulf of Mexico and 10 MMBbl in the North Sea Dumbarton field
area. The 2008 increase in proved reserves includes 13 MMBbl in the US
Wattenberg field, primarily due to infill drilling activities, and 9 MMBbl
in China. The 2009 increase in proved reserves includes 20 MMBbl related
to the ongoing development of the US Wattenberg field, 11 MMBbl in the
deepwater Gulf of Mexico for the Santa Cruz, Isabela and Swordfish fields,
and 26 MMBbl in Equatorial Guinea for the Aseng field.
|
(4)
|
Equatorial
Guinea production includes sales from the Alba field to the Alba LPG plant
of 3 MMBbl in 2009, 3 MMBbl in 2008, and 3 MMBbl in
2007.
|
(5)
|
The
decrease is due to sale of our Argentina assets. See Note 4. Acquisitions
and Divestitures.
|
Natural
Gas and Casinghead Gas (Bcf)
|
||||||||||||||||||||
United
States
|
Equatorial
Guinea
|
Israel
|
Other
Int'l (1)
|
Total
|
||||||||||||||||
Proved
Reserves as of:
|
||||||||||||||||||||
December
31, 2006
|
1,739 | 945 | 360 | 187 | 3,231 | |||||||||||||||
Revisions
of Previous Estimates (2)
|
(67 | ) | 44 | - | 28 | 5 | ||||||||||||||
Extensions,
Discoveries and Other Additions (3)
|
316 | - | - | 3 | 319 | |||||||||||||||
Purchase
of Minerals in Place
|
3 | - | - | - | 3 | |||||||||||||||
Sale
of Minerals in Place
|
- | - | - | - | - | |||||||||||||||
Production
|
(151 | ) | (48 | ) | (41 | ) | (11 | ) | (251 | ) | ||||||||||
December
31, 2007
|
1,840 | 941 | 319 | 207 | 3,307 | |||||||||||||||
Revisions
of Previous Estimates (2)
|
(253 | ) | 34 | 1 | 8 | (210 | ) | |||||||||||||
Extensions,
Discoveries and Other Additions (3)
|
345 | 78 | 4 | - | 427 | |||||||||||||||
Purchase
of Minerals in Place (4)
|
72 | - | - | - | 72 | |||||||||||||||
Sale
of Minerals in Place
|
- | - | - | - | - | |||||||||||||||
Production
|
(145 | ) | (75 | ) | (51 | ) | (10 | ) | (281 | ) | ||||||||||
December
31, 2008
|
1,859 | 978 | 273 | 205 | 3,315 | |||||||||||||||
Revisions
of Previous Estimates (2)
|
(397 | ) | 49 | (2 | ) | (350 | ) | |||||||||||||
Extensions,
Discoveries and Other Additions (3)
|
211 | - | 5 | 2 | 218 | |||||||||||||||
Purchase
of Minerals in Place
|
6 | - | - | - | 6 | |||||||||||||||
Sale
of Minerals in Place
|
- | - | - | - | - | |||||||||||||||
Production
|
(145 | ) | (87 | ) | (42 | ) | (11 | ) | (285 | ) | ||||||||||
December
31, 2009
|
1,534 | 940 | 234 | 196 | 2,904 | |||||||||||||||
Proved
Developed Reserves as of:
|
||||||||||||||||||||
December
31, 2006
|
1,255 | 360 | 303 | 187 | 2,105 | |||||||||||||||
December
31, 2007
|
1,259 | 830 | 263 | 204 | 2,556 | |||||||||||||||
December
31, 2008
|
1,268 | 700 | 216 | 201 | 2,385 | |||||||||||||||
December
31, 2009
|
1,114 | 638 | 191 | 192 | 2,135 | |||||||||||||||
Proved
Undeveloped Reserves as of:
|
||||||||||||||||||||
December
31, 2006
|
484 | 585 | 57 | - | 1,126 | |||||||||||||||
December
31, 2007
|
581 | 111 | 56 | 3 | 751 | |||||||||||||||
December
31, 2008
|
591 | 278 | 57 | 4 | 930 | |||||||||||||||
December
31, 2009
|
420 | 302 | 43 | 4 | 769 |
(1)
|
Other
International includes the North Sea, Ecuador and China. See Note 3.
Impairments for a discussion of impairment charges related to our
investment in Ecuador.
|
(2)
|
The
2007 negative revisions within the US are primarily due to 103 Bcf of
natural gas being reflected in the proved oil reserves table as NGLs,
partially offset by positive revisions resulting from an increase in
commodity price. The 2008 negative revisions in the US are primarily due
to lower year-end prices (109 Bcf), as well as additional natural gas
volumes being reflected in the proved oil reserves table as NGLs. The 2009
negative revisions in the US are primarily due to lower year-end prices
(224 Bcf), reclassifications of proved undeveloped reserves to probable
reserves as a result of the SEC’s new five year development rule (75 Bcf),
and increased lease operating expense and various well performance issues
(98 Bcf). Equatorial Guinea’s positive revisions in 2007, 2008 and 2009
are primarily due to additional production allowances related to LNG
sales. The 2007 positive revisions in Ecuador are related to better than
expected well performance.
|
(3)
|
The
2007 increase in US proved reserves includes 142 Bcf in the Wattenberg
field, 83 Bcf in the Piceance basin and 19 Bcf in the Niobrara trend,
primarily due to infill drilling activities. The 2008 increase in US
proved reserves includes 106 Bcf in the Wattenberg field and 173 Bcf in
the Rocky Mountain area, primarily in the Piceance basin and Niobrara
trend, primarily due to infill drilling activities. The remaining increase
is due to other development programs in the US Northern and Southern
regions. The 2009 increase in US proved reserves is primarily due to
ongoing low-risk development programs onshore in the Wattenberg field, the
Rocky Mountain area, and East
Texas.
|
(4)
|
Purchase
of minerals in place is primarily due to the Mid-continent acquisition.
See Note 4. Acquisitions and
Divestitures.
|
United
States
|
Equatorial
Guinea
|
Israel
|
Other
Int'l (1)
|
Total
|
||||||||||||||||
(millions)
|
||||||||||||||||||||
Year
Ended December 31, 2009
|
||||||||||||||||||||
Revenues
|
||||||||||||||||||||
Sales
(2)
|
$ | 1,341 | $ | 340 | $ | 144 | $ | 235 | $ | 2,060 | ||||||||||
Sales
to Affiliated Power Plant
|
- | - | - | 35 | 35 | |||||||||||||||
Total
Revenues
|
1,341 | 340 | 144 | 270 | 2,095 | |||||||||||||||
Production
Costs (3)
|
417 | 50 | 13 | 79 | 559 | |||||||||||||||
Exploration
Expense
|
75 | 1 | 10 | 24 | 110 | |||||||||||||||
DD&A
|
689 | 38 | 21 | 50 | 798 | |||||||||||||||
Asset
Impairments
|
504 | - | - | 100 | 604 | |||||||||||||||
Income
before Income Taxes
|
(344 | ) | 251 | 100 | 17 | 24 | ||||||||||||||
Income
Tax Expense
|
(108 | ) | 59 | 20 | 6 | (23 | ) | |||||||||||||
Results
of Operations (4)
|
$ | (236 | ) | $ | 192 | $ | 80 | $ | 11 | $ | 47 | |||||||||
Year
Ended December 31, 2008
|
||||||||||||||||||||
Revenues
|
||||||||||||||||||||
Sales
(2)
|
$ | 2,459 | $ | 500 | $ | 157 | $ | 535 | $ | 3,651 | ||||||||||
Sales
to Affiliated Power Plant
|
- | - | - | 30 | 30 | |||||||||||||||
Total
Revenues
|
2,459 | 500 | 157 | 565 | 3,681 | |||||||||||||||
Production
Costs (3)
|
470 | 42 | 12 | 123 | 647 | |||||||||||||||
Exploration
Expense
|
111 | 7 | 4 | 60 | 182 | |||||||||||||||
DD&A
|
653 | 34 | 23 | 75 | 785 | |||||||||||||||
Asset
Impairments
|
224 | - | - | - | 224 | |||||||||||||||
Income
before Income Taxes
|
1,001 | 417 | 118 | 307 | 1,843 | |||||||||||||||
Income
Tax Expense
|
339 | 99 | 22 | 151 | 611 | |||||||||||||||
Results
of Operations (4)
|
$ | 662 | $ | 318 | $ | 96 | $ | 156 | $ | 1,232 | ||||||||||
Year
Ended December 31, 2007
|
||||||||||||||||||||
Revenues
|
||||||||||||||||||||
Sales
(2)
|
$ | 1,952 | $ | 406 | $ | 113 | $ | 495 | $ | 2,966 | ||||||||||
Sales
to Affiliated Power Plant
|
- | - | - | 35 | 35 | |||||||||||||||
Total
Revenues
|
1,952 | 406 | 113 | 530 | 3,001 | |||||||||||||||
Production
Costs (3)
|
390 | 42 | 10 | 107 | 549 | |||||||||||||||
Exploration
Expense
|
122 | 26 | 1 | 38 | 187 | |||||||||||||||
DD&A
|
595 | 25 | 18 | 112 | 750 | |||||||||||||||
Asset
Impairments
|
4 | - | - | - | 4 | |||||||||||||||
Income
before Income Taxes
|
841 | 313 | 84 | 273 | 1,511 | |||||||||||||||
Income
Tax Expense
|
191 | 84 | 14 | 128 | 417 | |||||||||||||||
Results
of Operations (4)
|
$ | 650 | $ | 229 | $ | 70 | $ | 145 | 1,094 |
(1)
|
Other
International includes the North Sea, Ecuador, China, Cameroon, Cyprus,
Argentina (through February 2008) and other new
ventures.
|
(2)
|
Includes
impact resulting from applying cash flow hedge accounting for related
commodity derivative instruments. See Note 6. Derivative Instruments and
Hedging Activities.
|
(3)
|
Production
costs from oil and gas producing activities consist of lease operating
expense, production and ad valorem taxes, transportation expense, and
general and administrative expense supporting oil and gas
operations.
|
(4)
|
Results
of operations from oil and gas producing activities exclude the
mark-to-market gain or loss on commodity derivative instruments, corporate
overhead and interest costs. See Note 6. Derivative Instruments and
Hedging Activities.
|
|
Costs
Incurred in Oil and Gas Property Acquisition, Exploration and Development
Activities (Unaudited) (1)
|
Costs
incurred in connection with crude oil and natural gas acquisition,
exploration and development are as
follows:
|
United
States
|
Equatorial
Guinea
|
Israel
|
Other
Int'l (2)
|
Total
|
||||||||||||||||
(millions)
|
||||||||||||||||||||
Year
Ended December 31, 2009
|
||||||||||||||||||||
Property
Acquisition Costs
|
||||||||||||||||||||
Proved
(3)
|
$ | (5 | ) | $ | - | $ | - | $ | - | $ | (5 | ) | ||||||||
Unproved
(4)
|
89 | 1 | - | 2 | 92 | |||||||||||||||
Total
Acquisition Costs
|
84 | 1 | - | 2 | 87 | |||||||||||||||
Exploration
Costs (5)
|
189 | 30 | 81 | 13 | 313 | |||||||||||||||
Development
Costs
(6)
|
711 | 100 | 33 | 129 | 973 | |||||||||||||||
Total
Consolidated Operations
|
$ | 984 | $ | 131 | $ | 114 | $ | 144 | $ | 1,373 | ||||||||||
Year
Ended December 31, 2008
|
||||||||||||||||||||
Property
Acquisition Costs
|
||||||||||||||||||||
Proved
(3)
|
$ | 256 | $ | - | $ | - | $ | - | $ | 256 | ||||||||||
Unproved
(4)
|
296 | - | - | 6 | 302 | |||||||||||||||
Total
Acquisition Costs
|
552 | - | - | 6 | 558 | |||||||||||||||
Exploration
Costs (5)
|
322 | 105 | 28 | 62 | 517 | |||||||||||||||
Development
Costs
(6)
|
1,106 | 38 | 13 | 108 | 1,265 | |||||||||||||||
Total
Consolidated Operations
|
$ | 1,980 | $ | 143 | $ | 41 | $ | 176 | $ | 2,340 | ||||||||||
Year
Ended December 31, 2007
|
||||||||||||||||||||
Property
Acquisition Costs
|
||||||||||||||||||||
Proved
|
$ | 11 | $ | - | $ | - | $ | - | $ | 11 | ||||||||||
Unproved
|
145 | - | - | 1 | 146 | |||||||||||||||
Total
Acquisition Costs
|
156 | - | - | 1 | 157 | |||||||||||||||
Exploration
Costs
|
184 | 131 | 2 | 103 | 420 | |||||||||||||||
Development
Costs
(6)
|
1,081 | 15 | 25 | 70 | 1,191 | |||||||||||||||
Total
Consolidated Operations
|
$ | 1,421 | $ | 146 | $ | 27 | $ | 174 | $ | 1,768 |
(1)
|
Costs
incurred include capitalized and expensed
items.
|
(2)
|
Other
International includes the North Sea, Ecuador, China, Cameroon, Cyprus,
Argentina (through February 2008) and other new
ventures.
|
(3)
|
2009
proved property acquisition costs include a $6 million downward purchase
price adjustment related to the Mid-continent acquisition. 2008 proved
property acquisition costs include $254 million related to the
Mid-continent acquisition.
|
(4)
|
2009
unproved property acquisition costs include $56 million for deepwater Gulf
of Mexico lease blocks and the remainder primarily for other onshore US
lease acquisitions. 2008 unproved property acquisition costs include $179
million for deepwater Gulf of Mexico lease blocks, $38 million related to
the Mid-continent acquisition, $39 million related to lease acquisitions
in East Texas and the remainder primarily for other onshore US lease
acquisitions.
|
(5)
|
2009
exploration costs include drilling and completion costs of $57 million in
deepwater Gulf of Mexico, $19 million in Equatorial Guinea and $71 million
in Israel. 2008 exploration costs include drilling and completion costs of
$72 million in deepwater Gulf of Mexico, $98 million in Equatorial Guinea
and $25 million in Israel.
|
(6)
|
Worldwide
development costs include amounts spent to develop proved undeveloped
reserves of approximately $440 million in 2009, $528 million in 2008 and
$390 million in 2007. Equatorial Guinea development costs for 2009 include
a non-cash accrual of $29 million related to estimated construction
progress to date on an FPSO to be used in the development of the
Aseng field in Equatorial Guinea. These capitalized costs will be included
in development costs as the FPSO is constructed. US development costs
include increases in asset retirement obligations of $11 million in 2009,
$34 million in 2008 and $24 million in 2007. Other international
development costs include increases in asset retirement obligations
of $5 million in 2009, $18 million in 2008 and $9 million in
2007.
|
December
31,
|
||||||||
2009
|
2008
|
|||||||
(millions)
|
||||||||
Unproved
Oil and Gas Properties (1)
|
$ | 874 | $ | 961 | ||||
Proved
Oil and Gas Properties
(2)
|
11,710 | 11,002 | ||||||
Total
Oil and Gas Properties
|
12,584 | 11,963 | ||||||
Accumulated
DD&A
|
(3,809 | ) | (3,054 | ) | ||||
Net
Capitalized Costs
|
$ | 8,775 | $ | 8,909 |
(1)
|
Unproved
oil and gas properties includes $263 million and $465 million at December
31, 2009 and 2008, respectively, remaining from the allocation of costs to
unproved properties acquired in the Patina Merger and the acquisition of
U.S. Exploration.
|
(2)
|
Proved
oil and gas properties include asset retirement costs of $176 million and
$180 million at December 31, 2009 and 2008,
respectively.
|
United
States
|
Equatorial
Guinea
|
Israel
|
Other
Int'l (1)
|
Total
|
||||||||||||||||
(millions)
|
||||||||||||||||||||
December
31, 2009
|
||||||||||||||||||||
Future
Cash Inflows (2)
|
$ | 16,196 | $ | 5,151 | $ | 769 | $ | 2,832 | $ | 24,948 | ||||||||||
Future
Production Costs (3)
|
5,390 | 1,185 | 96 | 983 | 7,654 | |||||||||||||||
Future
Development Costs
|
3,056 | 1,059 | 126 | 315 | 4,556 | |||||||||||||||
Future
Income Tax Expense
|
2,227 | 956 | 135 | 630 | 3,948 | |||||||||||||||
Future
Net Cash Flows
|
5,523 | 1,951 | 412 | 904 | 8,790 | |||||||||||||||
10%
Annual Discount for Estimated Timing of Cash Flows
|
2,672 | 814 | 93 | 279 | 3,858 | |||||||||||||||
Standardized
Measure of Discounted Future Net Cash Flows
|
$ | 2,851 | $ | 1,137 | $ | 319 | $ | 625 | $ | 4,932 | ||||||||||
December
31, 2008
|
||||||||||||||||||||
Future
Cash Inflows (2)
|
$ | 16,551 | $ | 3,277 | $ | 938 | $ | 2,299 | $ | 23,065 | ||||||||||
Future
Production Costs (3)
|
4,646 | 784 | 120 | 876 | 6,426 | |||||||||||||||
Future
Development Costs
|
3,082 | 62 | 160 | 349 | 3,653 | |||||||||||||||
Future
Income Tax Expense
|
2,594 | 774 | 173 | 473 | 4,014 | |||||||||||||||
Future
Net Cash Flows
|
6,229 | 1,657 | 485 | 601 | 8,972 | |||||||||||||||
10%
Annual Discount for Estimated Timing of Cash Flows
|
3,180 | 608 | 106 | 214 | 4,108 | |||||||||||||||
Standardized
Measure of Discounted Future Net Cash Flows
|
$ | 3,049 | $ | 1,049 | $ | 379 | $ | 387 | $ | 4,864 | ||||||||||
December
31, 2007
|
||||||||||||||||||||
Future
Cash Inflows (2)
|
$ | 30,733 | $ | 6,935 | $ | 858 | $ | 4,075 | $ | 42,601 | ||||||||||
Future
Production Costs (3)
|
5,936 | 1,112 | 180 | 1,025 | 8,253 | |||||||||||||||
Future
Development Costs
|
3,136 | 202 | 88 | 227 | 3,653 | |||||||||||||||
Future
Income Tax Expense
|
6,622 | 1,348 | 146 | 1,121 | 9,237 | |||||||||||||||
Future
Net Cash Flows
|
15,039 | 4,273 | 444 | 1,702 | 21,458 | |||||||||||||||
10%
Annual Discount for Estimated Timing of Cash Flows
|
7,398 | 1,705 | 163 | 541 | 9,807 | |||||||||||||||
Standardized
Measure of Discounted Future Net Cash Flows
|
$ | 7,641 | $ | 2,568 | $ | 281 | $ | 1,161 | $ | 11,651 |
(1)
|
Other
International includes the North Sea, Ecuador, China and Argentina. We
sold our Argentina assets in February
2008.
|
(2)
|
The
standardized measure of discounted future net cash flows for 2009, 2008
and 2007 does not include cash flows relating to anticipated future
methanol or electricity sales.
|
(3)
|
Production
costs include oil and gas lease operating expense, production and ad
valorem taxes, transportation expense and general and administrative
expense supporting oil and gas
operations.
|
United
States
|
Equatorial
Guinea
|
Israel
|
Other
Int'l (1)
|
Total
|
||||||||||||||||
December
31, 2009 (2)
|
||||||||||||||||||||
Average
Crude Oil Price per Bbl
|
$ | 50.80 | $ | 53.46 | $ | - | $ | 59.55 | $ | 52.45 | ||||||||||
Average
Natural Gas Price per Mcf
|
3.64 | 0.25 | 3.28 | 3.69 | 2.52 | |||||||||||||||
December
31, 2008
|
||||||||||||||||||||
Average
Crude Oil Price per Bbl
|
$ | 36.62 | $ | 40.51 | $ | - | $ | 40.05 | $ | 37.97 | ||||||||||
Average
Natural Gas Price per Mcf
|
4.99 | 0.25 | 3.43 | 3.82 | 3.39 | |||||||||||||||
December
31, 2007
|
||||||||||||||||||||
Average
Crude Oil Price per Bbl
|
$ | 88.00 | $ | 81.26 | $ | - | $ | 82.20 | $ | 85.62 | ||||||||||
Average
Natural Gas Price per Mcf
|
6.78 | 0.27 | 2.69 | 4.04 | 4.36 |
(1)
|
Other
International includes the North Sea, Ecuador, and China at December 31,
2009, 2008 and 2007 and also includes Argentina at December 31,
2007.
|
(2)
|
The
new SEC and FASB reserves reporting rules require the use of 12-month
average commodity prices instead of year-end commodity
prices.
|
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions)
|
||||||||||||
Imbalance
receivables
|
$ | 21 | $ | 7 | $ | 13 | ||||||
Imbalance
liabilities
|
12 | 8 | 10 | |||||||||
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(millions)
|
||||||||||||
Standardized
Measure of Discounted Future Net Cash Flows, Beginning of
Year
|
$ | 4,864 | $ | 11,651 | $ | 6,887 | ||||||
Changes
in Standardized Measure of Discounted Future Net Cash
Flows
|
||||||||||||
Sales
of Oil and Gas Produced, Net of Production Costs
|
(1,528 | ) | (3,030 | ) | (2,427 | ) | ||||||
Net
Changes in Prices and Production Costs
|
(878 | ) | (8,017 | ) | 5,266 | |||||||
Extensions,
Discoveries and Improved Recovery, Less Related Costs
|
815 | 400 | 1,635 | |||||||||
Changes
in Estimated Future Development Costs
|
(132 | ) | (883 | ) | (775 | ) | ||||||
Development
Costs Incurred During the Period
|
971 | 1,291 | 1,189 | |||||||||
Revisions
of Previous Quantity Estimates
|
436 | (617 | ) | 1,276 | ||||||||
Purchases
of Minerals in Place
|
5 | 182 | 6 | |||||||||
Sales
of Minerals in Place
|
- | (66 | ) | (95 | ) | |||||||
Accretion
of Discount
|
707 | 1,663 | 1,006 | |||||||||
Net
Change in Income Taxes
|
(75 | ) | 2,853 | (1,900 | ) | |||||||
Change
in Timing of Estimated Future Production and Other
|
(253 | ) | (563 | ) | (417 | ) | ||||||
Aggregate
Change in Standardized Measure of Discounted Future Net Cash
Flows
|
68 | (6,787 | ) | 4,764 | ||||||||
Standardized
Measure of Discounted Future Net Cash Flows, End of Year
|
$ | 4,932 | $ | 4,864 | $ | 11,651 |
Quarter
Ended
|
||||||||||||||||||||
March
31,
|
June
30,
|
Sep
30,
|
Dec
31,
|
Total
|
||||||||||||||||
(millions
except per share amounts)
|
||||||||||||||||||||
2009
(1)
|
||||||||||||||||||||
Revenues
|
$ | 441 | $ | 491 | $ | 621 | $ | 760 | $ | 2,313 | ||||||||||
Income
(Loss) Before Income Taxes
|
(374 | ) | (90 | ) | 115 | 85 | (264 | ) | ||||||||||||
Net
Income (Loss)
|
(188 | ) | (57 | ) | 107 | 8 | (131 | ) | ||||||||||||
Earnings
(Loss) Per Share
|
||||||||||||||||||||
Basic
(3)
|
$ | (1.09 | ) | $ | (0.33 | ) | $ | 0.62 | $ | 0.05 | $ | (0.75 | ) | |||||||
Diluted
(3)
|
(1.09 | ) | (0.33 | ) | 0.61 | 0.05 | $ | (0.75 | ) | |||||||||||
2008
(2)
|
||||||||||||||||||||
Revenues
|
$ | 1,025 | $ | 1,205 | $ | 1,098 | $ | 573 | $ | 3,901 | ||||||||||
Income
(Loss) Before Income Taxes
|
315 | (198 | ) | 1,454 | 490 | 2,061 | ||||||||||||||
Net
Income (Loss)
|
215 | (144 | ) | 974 | 305 | 1,350 | ||||||||||||||
Earnings
(Loss) Per Share
|
||||||||||||||||||||
Basic
(3)
|
$ | 1.25 | $ | (0.84 | ) | $ | 5.64 | $ | 1.77 | $ | 7.83 | |||||||||
Diluted
(3)
(4)
|
1.20 | (0.84 | ) | 5.37 | 1.72 | 7.58 |
(1)
|
First
quarter 2009 included the
following:
|
|
·
|
$73
million gain on commodity derivative instruments. (See Note 6. Derivative
Instruments and Hedging
Activities);
|
|
·
|
$437
million asset impairment charges (See Note 3. Asset Impairments);
and
|
|
·
|
$46
million reversal of Ecuador allowance for doubtful accounts (See Note 2.
Summary of Significant Accounting
Policies).
|
|
Second
quarter 2009 included the
following:
|
|
·
|
$139
million loss on commodity derivative instruments. (See Note 6. Derivative
Instruments and Hedging Activities);
and
|
|
·
|
$24
million gain on sale of interest in Argentina, which had been deferred
until government approval of the
sale.
|
|
Third
quarter 2009 included the
following:
|
|
·
|
$28
million loss on commodity derivative instruments (See Note 6. Derivative
Instruments and Hedging Activities);
and
|
|
·
|
$12
million write-down of SemCrude, L.P. receivable (See Note 17. Commitments
and Contingencies).
|
|
Fourth
quarter 2009 included the
following:
|
|
·
|
$16
million loss on commodity derivative instruments (See Note 6. Derivative
Instruments and Hedging
Activities);
|
|
·
|
$167
million asset impairment charges (See Note 3. Asset Impairments);
and
|
|
·
|
$97 million refund
of deepwater Gulf of Mexico royalties, including interest (See Note
2. Summary of Significant Accounting
Policies).
|
(2)
|
First
quarter 2008 included the
following:
|
|
·
|
$237
million loss on commodity derivative instruments. (See Note 6. Derivative
Instruments and Hedging
Activities).
|
|
Second
quarter 2008 included the
following:
|
|
·
|
$828
million loss on commodity derivative instruments. (See Note 6. Derivative
Instruments and Hedging
Activities).
|
|
Third
quarter 2008 included the
following:
|
|
·
|
$875
million gain on commodity derivative instruments (See Note 6. Derivative
Instruments and Hedging
Activities);
|
|
·
|
$38
million write-down of SemCrude, L.P. receivable (See Note 17. Commitments
and Contingencies); and
|
|
·
|
$38
million asset impairment charges (See Note 3. Asset
Impairments).
|
|
Fourth
quarter 2008 included the
following:
|
|
·
|
$630
million gain on commodity derivative instruments (See Note 6. Derivative
Instruments and Hedging Activities);
and
|
|
·
|
$256
million asset impairment charges (See Note 3. Asset
Impairments).
|
(3)
|
The
sum of the individual quarterly earnings (loss) per share amounts may not
agree with year-to-date earnings per share as each quarterly computation
is based on the income or loss for that quarter and the weighted average
number of shares outstanding during that
quarter.
|
(4)
|
The
diluted earnings per share calculations for the quarters ended September
30, 2008 and December 31, 2008 include decreases to net income of $29
million, net of tax, and $4 million, net of tax, respectively, related to
deferred compensation gains related to shares of our common stock held in
a rabbi trust.
|
Item 12. Security Ownership of
Certain Beneficial Owners and Management and Related
Stockholder Matters
|
(3)
|
Exhibits:
The exhibits required to be filed by this Item 15 are set forth in
the Index to Exhibits accompanying this
report.
|
NOBLE
ENERGY, INC.
|
|
(Registrant)
|
|
Date:
February 18, 2010
|
By:
/s/ Charles D. Davidson
|
Charles
D. Davidson,
|
|
Chairman
of the Board,
|
|
Chief
Executive Officer and Director
|
|
Date:
February 18, 2010
|
By:
/s/ Kenneth M. Fisher
|
Kenneth
M. Fisher,
|
|
Senior
Vice President, Chief Financial Officer
|
|
Date:
February 18, 2010
|
By:
/s/ Frederick B. Bruning
|
Frederick
B. Bruning,
|
|
Vice
President, Chief Accounting Officer
|
Signature
|
Capacity
in which signed
|
Date
|
||||||||
/s/
Charles D. Davidson
|
Chairman
of the Board,
|
February 18,
2010
|
||||||||
Charles
D. Davidson
|
Chief
Executive Officer and Director
|
|||||||||
(Principal
Executive Officer)
|
||||||||||
/s/
Kenneth M. Fisher
|
Senior
Vice President,
|
February 18,
2010
|
||||||||
Kenneth
M. Fisher
|
Chief
Financial Officer
|
|||||||||
(Principal
Financial Officer)
|
||||||||||
/s/
Frederick B. Bruning
|
Vice
President, Chief Accounting Officer
|
February 18,
2010
|
||||||||
Frederick
B. Bruning
|
(Principal
Accounting Officer)
|
|||||||||
/s/
Jeffrey L. Berenson
|
Director
|
February 18,
2010
|
||||||||
Jeffrey
L. Berenson
|
||||||||||
/s/
Michael A. Cawley
|
Director
|
February 18,
2010
|
||||||||
Michael
A. Cawley
|
||||||||||
/s/
Edward F. Cox
|
Director
|
February 18,
2010
|
||||||||
Edward
F. Cox
|
||||||||||
/s/
Thomas J. Edelman
|
Director
|
February 18,
2010
|
||||||||
Thomas
J. Edelman
|
||||||||||
/s/
Eric P. Grubman
|
Director
|
February 18,
2010
|
||||||||
Eric
P. Grubman
|
||||||||||
/s/
Kirby L. Hedrick
|
Director
|
February 18,
2010
|
||||||||
Kirby
L. Hedrick
|
||||||||||
/s/
Scott D. Urban
|
Director
|
February 18,
2010
|
||||||||
Scott
D. Urban
|
||||||||||
/s/
William T. Van Kleef
|
Director
|
February 18,
2010
|
||||||||
William
T. Van Kleef
|
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 June 1, 2009 (filed as
Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date
of Event: February 17, 2009) filed February 19, 2009 and incorporated
herein by reference).
|
|||
4.1
|
—
|
Certificate
of Designations of Series A Junior Participating Preferred Stock of
the Registrant dated August 27, 1997 (filed as Exhibit A of
Exhibit 4.1 to the Registrant’s Registration Statement on
Form 8-A filed on August 28, 1997 and incorporated herein
by reference).
|
|||
4.2
|
—
|
Certificate
of Designations of Series B Mandatorily Convertible Preferred Stock
of the Registrant dated November 9, 1999 (filed as
Exhibit 3.4 to the Registrant’s Annual Report on Form 10-K for
the year ended December 31, 1999 and incorporated herein by
reference).
|
|||
4.3
|
—
|
Indenture
dated as of February 27, 2009 between Noble Energy, Inc. and Wells
Fargo Bank, National Association, as Trustee, relating to the Registrant’s
8¼% Notes Due March 1, 2019 (filed as Exhibit 4.1 to the Registrant’s
Current Report on Form 8-K (Date of Event: February 24, 2009) filed
February 27, 2009 and incorporated herein by
reference.)
|
|||
4.4
|
—
|
First
Supplemental Indenture dated as of February 27, 2009, to Indenture
dated as of February 27, 2009 between Noble Energy, Inc. and Wells
Fargo Bank, National Association, as Trustee, relating to the Registrant’s
8¼% Notes Due March 1, 2019 (including the form of 2019 Notes) (filed as
Exhibit 4.2 to the Registrant’s Current Report on Form 8-K (Date of
Event: February 24, 2009) filed February 27, 2009 and incorporated herein
by reference).
|
|||
4.5
|
—
|
Indenture
dated as of October 14, 1993 between the Registrant and U.S.
Trust Company of Texas, N.A., as Trustee, relating to the Registrant’s 7¼%
Notes Due 2023, including form of the Registrant’s 7¼% Notes Due 2023
(filed as Exhibit 4.1 to the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended September 30, 1993 and
incorporated herein by reference).
|
|||
4.6
|
—
|
Indenture
relating to Senior Debt Securities dated as of April 1, 1997
between the Registrant and U.S. Trust Company of Texas, N.A., as Trustee
(filed as Exhibit 4.1 to the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended March 31, 1997 and
incorporated herein by reference).
|
|||
4.7
|
—
|
First
Indenture Supplement relating to $250 million of the Registrant’s 8%
Senior Notes Due 2027 dated as of April 1, 1997 between the
Registrant and U.S. Trust Company of Texas, N.A., as Trustee (filed as
Exhibit 4.2 to the Registrant’s Quarterly Report on Form 10-Q
for the quarter ended March 31, 1997 and incorporated herein by
reference).
|
|||
4.8
|
—
|
Second
Indenture Supplement, between the Company and U.S. Trust Company of Texas,
N.A. as trustee, relating to $100 million of the Registrant’s 7¼%
Senior Debentures Due 2097 dated as of August 1, 1997 (filed as
Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q
for the quarter ended June 30, 1997 and incorporated herein by
reference).
|
|||
4.9
|
—
|
Third
Indenture Supplement relating to $200 million of the Registrant’s 5¼%
Notes due 2014 dated April 19, 2004 between the Company and the
Bank of New York Trust Company, N.A., as successor trustee to U.S. Trust
Company of Texas, N.A. (filed as Exhibit 4.1 to the Company’s
Registration Statement on Form S-4 (Registration No. 333-116092)
and incorporated herein by reference).
|
|||
10.1*
|
—
|
Noble
Energy, Inc. Retirement Restoration Plan dated effective as of January 1,
2009, (filed as Exhibit 10.1 to the Registrant’s Annual Report on Form
10-K for the year ended December 31, 2008 and incorporated herein by
reference).
|
|||
10.2*
|
—
|
Noble
Energy, Inc. Restoration Trust effective August 1, 2002
(filed as Exhibit 10.3 to the Registrant’s Annual Report on
Form 10-K for the year ended December 31, 2002 and
incorporated herein by reference).
|
|||
10.3*
|
—
|
Form of
Nonqualified Stock Option Agreement under the Noble Energy, Inc. 1992
Stock Option and Restricted Stock Plan (filed as Exhibit 10.1 to the
Registrant’s Current Report on Form 8-K (Date of Event:
February 1, 2005) filed February 7, 2005 and
incorporated herein by reference).
|
|||
10.4*
|
—
|
Form of
Restricted Stock Agreement under the Noble Energy, Inc. 1992 Stock
Option and Restricted Stock Plan, (filed as Exhibit 10.4 to the
Registrant’s Annual Report on Form 10-K for the year ended December 31,
2008 and incorporated herein by reference).
|
|||
10.5*
|
—
|
1988
Nonqualified Stock Option Plan for Non-Employee Directors of the
Registrant, as amended and restated, effective as of
April 27, 2004 (filed as Exhibit 10.2 to the Registrant’s
Quarterly Report on Form 10-Q for the quarter ended
June 30, 2004 and incorporated herein by
reference).
|
|||
10.6*
|
—
|
Form of
Indemnity Agreement entered into between the Registrant and each of the
Registrant’s directors and bylaw officers (filed as Exhibit 10.18 to
the Registrant’s Annual Report of Form 10-K for the year ended
December 31, 1995 and incorporated herein by
reference).
|
|||
10.7*
|
—
|
Letter
agreement dated February 1, 2002 between the Registrant and
Charles D. Davidson, terminating Mr. Davidson’s employment agreement
and entering into the attached Change of Control Agreement (filed as
Exhibit 10.17 to the Registrant’s Annual Report on Form 10-K for
the year ended December 31, 2001 and incorporated herein by
reference).
|
|||
10.8
|
—
|
$2.1 billion
Five-Year Credit Agreement, dated November 30, 2006, among Noble
Energy, Inc., JPMorgan Chase Bank, N.A., as administrative agent,
Wachovia Bank, National Association and The Royal Bank of Scotland PLC, as
co-syndication agents, Deutsche Bank Securities Inc., Citibank, N.A. and
The Bank of Tokyo-Mitsubishi UFJ, Ltd., as co-documentation agents, and
certain other commercial lending institutions named therein (filed as
Exhibit 10.1 to the Registrant’s Current Report on Form 8-K
(Date of Event: November 30, 2006), filed December 6, 2006 and
incorporated herein by reference).
|
|||
10.9*
|
—
|
Noble
Energy, Inc. 2005 Non-Employee Director Fee Deferral Plan, dated
December 11, 2008, and effective as of January 1, 2009, (filed
as Exhibit 10.20 to the Registrant’s Annual Report on Form 10-K for the
year ended December 31, 2008 and incorporated herein by
reference).
|
|||
10.10*
|
—
|
2005
Stock Plan for Non-Employee Directors of Noble Energy, Inc. (filed as
Exhibit 10.1 to the Registrant’s Current Report on Form 8-K
(Date of Event: April 26, 2005) filed April 29, 2005 and
incorporated herein by reference).
|
|||
10.11*
|
—
|
Form of
Stock Option Agreement under the Noble Energy, Inc. 2005 Non-Employee
Director Stock Plan (filed as Exhibit 10.1 to the Registrant’s
Quarterly Report on Form 10-Q for the quarter ended June 30,
2005 and incorporated herein by reference).
|
|||
10.12*
|
—
|
Amendment
to the 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc.
(effective September 1, 2008) (filed as Exhibit to the Registrant’s
Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and
incorporated herein by reference).
|
|||
10.13*
|
—
|
Form of
Restricted Stock Agreement under the Noble Energy, Inc. 2005
Non-Employee Director Stock Plan (filed as Exhibit 10.1 to the
Registrant’s Current Report on Form 8-K (Date of Event: January 27,
2009) filed on February 2, 2009 and incorporated herein by
reference).
|
10.14*
|
—
|
Form of
Restricted Stock Agreement under the Noble Energy, Inc. 1992 Stock
Option and Restricted Stock Plan, filed herewith.
|
|||
10.15*
|
—
|
Noble
Energy, Inc. 1992 Stock Option and Restricted Stock Plan (as amended
through April 28, 2009), (filed as exhibit 10.1 to Registrant’s Current
Report on Form 8-K (Date of Event: April 28, 2009) filed April 29, 2009
and incorporated herein by reference).
|
|||
10.16*
|
—
|
Noble
Energy, Inc. Change of Control Severance Plan for Executives (as
amended effective January 1, 2008), (filed as Exhibit 10.40 to the
Registrant’s Annual Report on Form 10-K for the year ended
December 31, 2007 and incorporated herein by
reference).
|
|||
10.17*
|
—
|
Noble
Energy, Inc. Change of Control Agreement (as amended effective
January 1, 2008), (filed as Exhibit 10.41 to the Registrant’s Annual
Report on Form 10-K for the year ended December 31, 2007
and incorporated herein by reference).
|
|||
10.18*
|
—
|
Noble
Energy, Inc. 2004 Long-Term Incentive Plan (as amended effective
January 1, 2008), (filed as Exhibit 10.42 to the Registrant’s Annual
Report on Form 10-K for the year ended December 31, 2007
and incorporated herein by reference).
|
|||
10.19*
|
—
|
Noble
Energy, Inc. 2005 Deferred Compensation Plan (as amended effective
January 1, 2009), (filed as Exhibit 10.31 to the Registrant’s Annual
Report on Form 10-K for the year ended December 31, 2008 and incorporated
herein by reference).
|
|||
12.1
|
—
|
Calculation
of ratio of earnings to fixed charges, filed herewith.
|
|||
21
|
—
|
Subsidiaries,
filed herewith.
|
|||
23.1
|
—
|
Consent
of Independent Registered Public Accounting Firm—KPMG LLP, filed
herewith.
|
|||
23.2
|
—
|
Consent
of Independent Registered Public Accounting Firm—PricewaterhouseCoopers
LLP, filed herewith.
|
|||
23.3
|
—
|
Consent
of Independent Petroleum Engineers and Geologists—Netherland,
Sewell & Associates, Inc., filed
herewith.
|
|||
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), filed
herewith.
|
|||
31.2
|
—
|
Certification
of the Company’s Chief Financial Officer Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241), filed
herewith.
|
|||
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), filed
herewith.
|
|||
32.2
|
—
|
Certification
of the Company’s Chief Financial Officer Pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), filed
herewith.
|
|||
99.1
|
—
|
Report
of Independent Public Accounting Firm—PricewaterhouseCoopers LLP, filed
herewith.
|
|||
99.2
|
—
|
Report
of Netherland, Sewell & Associates, Inc., filed
herewith.
|
|||
101
|
—
|
The
following materials from the Noble Energy, Inc. Annual Report on Form 10-K
for the year ended December 31, 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, (v) Consolidated Statements of Comprehensive Income
and (vi) Notes to the Consolidated Financial Statements, tagged as blocks
of text.
|
|||
*
|
Management
contract or compensatory plan or arrangement required to be filed as an
exhibit hereto.
|
||||
**
|
Copies
of exhibits will be furnished upon prepayment of 25 cents per page.
Requests should be addressed to the Senior Vice President and Chief
Financial Officer, Noble Energy, Inc., 100 Glenborough Drive,
Suite 100, Houston, Texas
77067.
|
Bbl(s)
|
Barrel(s)
|
Bcf
|
Billion
cubic feet
|
Bcfe
|
Billion
cubic feet equivalent
|
Boe
|
Barrels
oil equivalent; gas is converted on the basis of six Mcf of gas per one
barrel of oil, condensate or natural gas liquids
|
Boepd
|
Barrels
oil equivalent per day
|
Bopd
|
Barrels
oil per day
|
Bpd
|
Barrels
per day
|
Btu
|
British
thermal unit
|
GW
|
Gigawatt
|
KWh
|
Kilowatt
hours
|
LNG
|
Liquefied
natural gas
|
LPG
|
Liquefied
petroleum gas
|
MBbls
|
Thousand
barrels
|
MBoe
|
Thousand
barrels oil equivalent
|
MBoepd
|
Thousand
barrels oil equivalent per day
|
MBopd
|
Thousand
barrels per day
|
MBpd
|
Thousand
barrels per day
|
Mcf
|
Thousand
cubic feet
|
Mcfe
|
Thousand
cubic feet equivalent
|
MMBbls
|
Million
barrels
|
MMBoe
|
Million
barrels oil equivalent
|
MMBtu
|
Million
British thermal units
|
MMBtupd
|
Million
British thermal units per day
|
MMcf
|
Million
cubic feet
|
MMcfe
|
Million
cubic feet equivalent
|
MMcfepd
|
Million
cubic feet equivalent per day
|
MMcfpd
|
Million
cubic feet per day
|
MMgal
|
Million
gallons
|
MTpd
|
Metric
tons per day
|
MW
|
Megawatt
|
NGL
|
Natural
gas liquid
|
Tcfe
|
Trillion
cubic feet equivalent
|