x
|
ANNUAL REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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o
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TRANSITION REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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Delaware
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73-0785597
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(State
of incorporation)
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(I.R.S.
employer identification number)
|
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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
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New
York Stock Exchange
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Preferred
Stock Purchase Rights
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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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1
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||
19
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25
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25
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25
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Executive Officers |
25
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27
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29
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30
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55
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56
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108
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108
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108
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109
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109
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109
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109
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109
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109
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40 | 395 | 9 | $ | 75.53 | $ | 8.12 | $ | 50.15 | $ | 10.43 | ||||||||||||
15 | 206 | - | 88.95 | 0.27 | - | 2.17 | ||||||||||||||||
10 | 5 | - | 100.56 | 10.54 | - | 14.30 | ||||||||||||||||
- | 139 | - | - | 3.10 | - | 1.07 | ||||||||||||||||
- | 22 | - | - | - | - | - | ||||||||||||||||
4 | - | - | 82.66 | - | - | 15.94 | ||||||||||||||||
69 | 767 | 9 | 82.60 | 5.04 | 50.15 | $ | 7.84 | |||||||||||||||
2 | - | 6 | 96.77 | - | 58.81 | |||||||||||||||||
71 | 767 | 15 | $ | 82.96 | $ | 5.04 | $ | 53.45 | ||||||||||||||
42 | 412 | - | $ | 53.22 | $ | 7.51 | - | $ | 8.49 | |||||||||||||
15 | 132 | - | 71.27 | 0.29 | - | 2.89 | ||||||||||||||||
13 | 6 | - | 76.47 | 6.54 | - | 9.81 | ||||||||||||||||
- | 111 | - | - | 2.79 | - | 1.14 | ||||||||||||||||
- | 26 | - | - | - | - | - | ||||||||||||||||
7 | - | - | 53.69 | - | - | 12.06 | ||||||||||||||||
77 | 687 | - | 60.61 | 5.26 | - | $ | 6.99 | |||||||||||||||
2 | - | 6 | 74.87 | - | 48.87 | |||||||||||||||||
79 | 687 | 6 | $ | 60.94 | $ | 5.26 | $ | 48.87 | ||||||||||||||
46 | 452 | - | $ | 50.68 | $ | 6.61 | - | $ | 8.12 | |||||||||||||
18 | 45 | - | 62.51 | 0.37 | - | 2.86 | ||||||||||||||||
4 | 8 | - | 67.43 | 8.00 | - | 10.08 | ||||||||||||||||
- | 93 | - | - | 2.72 | - | 1.60 | ||||||||||||||||
- | 25 | - | - | - | - | - | ||||||||||||||||
7 | - | - | 52.05 | - | - | 9.74 | ||||||||||||||||
75 | 623 | - | 54.47 | 5.55 | - | $ | 6.97 | |||||||||||||||
2 | - | 6 | 66.60 | - | 40.10 | |||||||||||||||||
77 | 623 | 6 | $ | 54.75 | $ | 5.55 | $ | 40.10 |
1.0 | - | 1.0 | 837.2 | 42.0 | 879.2 | ||||||||||||||
14.6 | 2.0 | 16.6 | 30.9 | 2.0 | 32.9 | ||||||||||||||
1.3 | 1.3 | - | - | - | |||||||||||||||
- | 0.4 | 0.4 | 0.6 | 0.3 | 0.9 | ||||||||||||||
- | - | - | - | - | - | ||||||||||||||
- | 0.5 | 0.5 | - | - | - | ||||||||||||||
16.9 | 2.9 | 19.8 | 868.7 | 44.3 | 913.0 | ||||||||||||||
13.9 | 1.9 | 15.8 | 738.0 | 24.5 | 762.5 | ||||||||||||||
0.3 | 2.6 | 2.9 | 19.6 | 3.1 | 22.7 | ||||||||||||||
2.6 | 0.5 | 3.1 | - | - | - | ||||||||||||||
0.5 | - | 0.5 | - | - | - | ||||||||||||||
- | - | - | 0.4 | - | 0.4 | ||||||||||||||
- | 0.1 | 0.1 | 6.7 | - | 6.7 | ||||||||||||||
17.3 | 5.1 | 22.4 | 764.7 | 27.6 | 792.3 | ||||||||||||||
5.5 | 4.6 | 10.1 | 521.4 | 4.6 | 526.0 | ||||||||||||||
0.8 | 4.4 | 5.2 | 145.2 | 0.9 | 146.1 | ||||||||||||||
- | 0.4 | 0.4 | 1.8 | - | 1.8 | ||||||||||||||
- | - | - | 1.1 | - | 1.1 | ||||||||||||||
- | - | - | 7.6 | - | 7.6 | ||||||||||||||
6.3 | 9.4 | 15.7 | 677.1 | 5.5 | 682.6 |
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·
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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 foreign imports;
|
|
·
|
the
price and availability of alternative
fuels;
|
|
·
|
the
availability of pipeline capacity and
infrastructure;
|
|
·
|
the
availability of crude oil transportation and refining
capacity;
|
|
·
|
weather
conditions;
|
|
·
|
electricity
dispatch;
|
|
·
|
domestic
and foreign governmental regulations and taxes;
and
|
|
·
|
the
overall economic environment.
|
|
·
|
limiting
our financial condition, liquidity, ability to finance planned capital
expenditures and results of
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;
|
|
·
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reducing
the carrying value of our crude oil and natural gas properties;
or
|
|
·
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limiting
our access to sources of capital, such as equity and long-term
debt.
|
|
·
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historical
production from the area compared with production from other
areas;
|
|
·
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the
assumed effects of regulations by governmental agencies, including the
impact of the SEC’s new oil and gas company reserve reporting
requirements;
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·
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assumptions
concerning future crude oil and natural gas
prices;
|
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·
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future
operating costs;
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·
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severance
and excise taxes;
|
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·
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development
costs; and
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·
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workover
and remedial costs.
|
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·
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war,
terrorist acts, civil disturbances, or territorial disputes, such as may
occur in regions that encompass our operations, including Ecuador, Israel
and West Africa;
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·
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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;
|
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·
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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;
|
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·
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laws
and policies of the US and foreign jurisdictions affecting foreign
investment, taxation, trade and business
conduct;
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·
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foreign
exchange restrictions;
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·
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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
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·
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other
hazards arising out of foreign governmental sovereignty over areas in
which we conduct operations.
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·
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pipeline
ruptures and spills;
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·
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fires;
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·
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explosions,
blowouts and cratering;
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·
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formations
with abnormal pressures;
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·
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equipment
malfunctions;
|
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·
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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
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·
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other
natural disasters.
|
|
·
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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.
|
|
·
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seeking
to acquire desirable producing properties or new leases for future
exploration;
|
|
·
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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.
|
|
·
|
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 current credit market crisis which has 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.
|
|
·
|
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;
|
|
·
|
our
liquidity and ability to finance our acquisition, exploration and
development activities;
|
|
·
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our
outlook on global economic conditions and
markets;
|
|
·
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market
conditions in the oil and gas
industry;
|
|
·
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our
ability to make and integrate acquisitions;
and
|
|
·
|
the
impact of governmental regulation.
|
Name
|
Age
|
Position
|
||
Charles
D. Davidson (1)
|
58
|
Chairman
of the Board, President, Chief Executive Officer and
Director
|
||
David
L. Stover (2)
|
51
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Executive
Vice President, Chief Operating Officer
|
||
Chris
Tong (3)
|
52
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Senior
Vice President, Chief Financial Officer
|
||
Ted
D. Brown (4)
|
53
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Senior
Vice President, Northern Region
|
||
Rodney
D. Cook (5)
|
51
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Senior
Vice President, International
|
||
Susan
M. Cunningham (6)
|
53
|
Senior
Vice President, Exploration
|
||
Arnold
J. Johnson
(7)
|
53
|
Senior
Vice President, General Counsel and Secretary
|
||
Andrea
Lee Robison
(8)
|
50
|
Vice
President, Human Resources
|
(1)
|
Charles
D. Davidson was elected President and Chief Executive Officer of Noble
Energy in October 2000 and Chairman of the Board in April 2001.
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 Executive Vice President and Chief Operating Officer
of Noble Energy in August 2006. Prior thereto, he served as Senior
Vice President of North America and Business Development from July 2004
through July 2006. 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)
|
Chris
Tong was elected a Senior Vice President and Chief Financial Officer of
Noble Energy in January 2005. Prior to January 2005, he had
served as Senior Vice President and Chief Financial Officer for Magnum
Hunter Resources, Inc. since August 1997. Prior thereto, he was
Senior Vice President of Finance of Tejas Acadian Holding Company and its
subsidiaries including Tejas Gas Corp., Acadian Gas Corporation and
Transok, Inc., all of which were wholly-owned subsidiaries of Tejas
Gas Corporation. Mr. Tong held these positions since
August 1996, and served in other treasury positions with Tejas
beginning August 1989. From 1980 to 1989, Mr. Tong served in
various energy lending capacities with several commercial banking
institutions. Prior to his banking career, Mr. Tong served over a
year with Superior Oil Company as a Reservoir Engineering
Assistant.
|
(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 in 1980 as a geologist
and held various exploration and development positions 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.
|
Dividends
|
||||||||||||
High
|
Low
|
Per
Share
|
||||||||||
2007
|
||||||||||||
First
quarter
|
$ | 60.69 | $ | 46.33 | $ | 0.075 | ||||||
Second
quarter
|
65.50 | 58.81 | 0.120 | |||||||||
Third
quarter
|
70.55 | 58.17 | 0.120 | |||||||||
Fourth
quarter
|
81.64 | 69.69 | 0.120 | |||||||||
2008
|
||||||||||||
First
quarter
|
$ | 81.35 | $ | 69.18 | $ | 0.120 | ||||||
Second
quarter
|
103.83 | 75.79 | 0.180 | |||||||||
Third
quarter
|
102.79 | 51.18 | 0.180 | |||||||||
Fourth
quarter
|
54.01 | 33.15 | 0.180 |
Stock
Repurchases. We did not repurchase any of our common stock in the
fourth quarter of 2008.
|
Number
of securities
|
|||||||||||
remaining
available
|
|||||||||||
Weighted-average
|
for
future issuance
|
||||||||||
Number
of securities
|
exercise
price of
|
under
equity
|
|||||||||
to
be issued upon
|
outstanding
|
compensation
plans
|
|||||||||
exercise
of
|
options,
warrants
|
(excluding
securities
|
|||||||||
Plan
Category
|
outstanding
options
|
and
rights
|
reflected
in column (a))
|
||||||||
(a)
|
(b)
|
(c)
|
|||||||||
Equity
compensation plans approved by security holders
|
6,082,375 | $ | 41.41 | 5,319,463 | |||||||
Equity
compensation plans not approved by security holders
|
- | - | - | ||||||||
Total
|
6,082,375 | $ | 41.41 | 5,319,463 |
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.
|
12/03
|
12/04
|
12/05
|
12/06
|
12/07
|
12/08
|
||||||||||||||
Noble
Energy, Inc.
|
$ | 100.00 | $ | 139.34 | $ | 182.87 | $ | 223.97 | $ | 365.44 | $ | 228.44 | |||||||
S&P
500
|
100.00 | 110.88 | 116.33 | 134.70 | 142.10 | 89.53 | |||||||||||||
Peer
Group
|
100.00 | 133.07 | 208.21 | 207.03 | 300.86 | 187.65 |
Year
Ended December 31,
|
||||||||||||||||||||
2008
|
2007
|
2006
(1)
|
2005
(2)
|
2004
|
||||||||||||||||
(in
millions, except as noted)
|
||||||||||||||||||||
Revenues
and Income
|
||||||||||||||||||||
Total
revenues
|
$ | 3,901 | $ | 3,272 | $ | 2,940 | $ | 2,187 | $ | 1,351 | ||||||||||
Income
from continuing operations
|
1,350 | 944 | 678 | 646 | 314 | |||||||||||||||
Net
income
|
1,350 | 944 | 678 | 646 | 329 | |||||||||||||||
Per
Share Data
|
||||||||||||||||||||
Basic
earnings per share -
|
||||||||||||||||||||
Income
from continuing operations
|
$ | 7.83 | $ | 5.52 | $ | 3.86 | $ | 4.20 | $ | 2.69 | ||||||||||
Net
income
|
7.83 | 5.52 | 3.86 | 4.20 | 2.82 | |||||||||||||||
Cash
dividends
|
0.660 | 0.435 | 0.275 | 0.150 | 0.100 | |||||||||||||||
Year-end
stock price
|
49.22 | 80.66 | 49.07 | 40.30 | 30.83 | |||||||||||||||
Basic
weighted average shares outstanding
|
173 | 171 | 176 | 154 | 117 | |||||||||||||||
Cash
Flows
|
||||||||||||||||||||
Net
cash provided by operating activities
|
$ | 2,285 | $ | 2,017 | $ | 1,730 | $ | 1,240 | $ | 708 | ||||||||||
Additions
to property, plant and equipment
|
1,971 | 1,414 | 1,357 | 786 | 554 | |||||||||||||||
Acquisitions
|
292 | - | 412 | 1,111 | - | |||||||||||||||
Financial
Position
|
||||||||||||||||||||
Cash
and cash equivalents
|
1,140 | 660 | 153 | 110 | 180 | |||||||||||||||
Commodity
derivative instruments - current
|
437 | 15 | 35 | 29 | 29 | |||||||||||||||
Property,
plant, and equipment, net
|
9,004 | 7,945 | 7,171 | 6,199 | 2,181 | |||||||||||||||
Goodwill
|
759 | 761 | 781 | 863 | - | |||||||||||||||
Total
assets
|
12,384 | 10,831 | 9,589 | 8,878 | 3,436 | |||||||||||||||
Long-term
obligations -
|
||||||||||||||||||||
Long-term
debt
|
2,241 | 1,851 | 1,801 | 2,031 | 880 | |||||||||||||||
Deferred
income taxes
|
2,174 | 1,984 | 1,758 | 1,201 | 180 | |||||||||||||||
Commodity
derivative instruments
|
2 | 83 | 329 | 758 | 10 | |||||||||||||||
Asset
retirement obligations
|
184 | 131 | 128 | 279 | 175 | |||||||||||||||
Other
|
300 | 337 | 275 | 280 | 69 | |||||||||||||||
Shareholders'
equity
|
6,309 | 4,809 | 4,114 | 3,090 | 1,460 | |||||||||||||||
Operations
Information
|
||||||||||||||||||||
Consolidated
crude oil sales (MBopd)
|
69 | 77 | 75 | 57 | 44 | |||||||||||||||
Average
realized price ($/Bbl) (3)
|
$ | 82.60 | $ | 60.61 | $ | 54.47 | $ | 45.35 | $ | 34.48 | ||||||||||
Consolidated
natural gas sales (MMcfpd)
|
767 | 687 | 623 | 508 | 367 | |||||||||||||||
Average
realized price ($/Mcf) (3)
|
$ | 5.04 | $ | 5.26 | $ | 5.55 | $ | 5.78 | $ | 4.76 | ||||||||||
Consolidated
NGL sales (MBpd) (4)
|
9 | - | - | - | - | |||||||||||||||
Average
realized price ($/Bbl)
|
$ | 50.15 | $ | - | $ | - | $ | - | $ | - | ||||||||||
Proved
Reserves
|
||||||||||||||||||||
Crude
oil, condensate and NGL reserves (MMBbl)
|
311 | 329 | 296 | 291 | 193 | |||||||||||||||
Natural
gas reserves (Bcf)
|
3,315 | 3,307 | 3,231 | 3,091 | 1,987 | |||||||||||||||
Total
reserves (MMBoe)
|
864 | 880 | 835 | 806 | 525 | |||||||||||||||
Number
of employees
|
1,571 | 1,398 | 1,243 | 1,171 | 559 |
(1)
|
Includes
effect of acquisition of U.S. Exploration and sale of Gulf of Mexico shelf
properties. See Item 8. Financial Statements and Supplementary Data—Note 4—Acquisitions and Divestitures for additional
information.
|
(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
income of $1.4 billion, a 43% increase over
2007;
|
|
·
|
$440
million gain on commodity derivative
instruments;
|
|
·
|
diluted
earnings per share of $7.58, a 39% increase over
2007;
|
|
·
|
cash
flows provided by operating activities of $2.3 billion, a 13% increase
over 2007;
|
|
·
|
$294
million asset impairment charges;
|
|
·
|
$38
million write-down of receivable from Semcrude,
L.P.;
|
|
·
|
year-end
cash balance of $1.1 billion, a $480 million increase over the prior year
ending cash balance; and
|
|
·
|
year-end
ratio of debt-to-book capital of 26% as compared with 28% at December 31,
2007.
|
|
·
|
significant
oil discovery at the Gunflint prospect in the deepwater Gulf of
Mexico;
|
|
·
|
continued
production growth in the Rocky Mountains area of our US
operations;
|
|
·
|
successful
Benita oil appraisal well, offshore Equatorial
Guinea;
|
|
·
|
exploration
discoveries offshore Equatorial Guinea at Diega and
Felicita;
|
|
·
|
start-up
of Phase 2 at the North Sea Dumbarton
development;
|
|
·
|
acquisition
of producing properties in western
Oklahoma;
|
|
·
|
expanded
acreage position onshore North
America;
|
|
·
|
successful
appraisal of the South Raton discovery in the deepwater Gulf of
Mexico;
|
|
·
|
production
start-up at the Raton gas development in the deepwater Gulf of
Mexico;
|
|
·
|
new
Ticonderoga development wells brought online in the deepwater Gulf of
Mexico;
|
|
·
|
successful
high bids on 15 deepwater Gulf of Mexico lease blocks in the central Gulf
of Mexico lease sale; and
|
|
·
|
record
annual natural gas production in Israel of 139
MMcfpd.
|
|
·
|
the
amount of development capital
expenditures;
|
|
·
|
higher
sales of natural gas from the Alba field in Equatorial
Guinea;
|
|
·
|
growth
in demand for natural gas in Israel;
and
|
|
·
|
growing
production from our Rocky Mountains assets, where we are continuing an
active drilling program;
|
|
·
|
natural
field decline in the deepwater Gulf of Mexico, Gulf Coast and
Mid-continent areas of our US
operations.
|
|
·
|
overall
level and timing of capital expenditures, as discussed below, which,
dependent upon our drilling success, are expected to result in near-term
production growth;
|
|
·
|
potential
hurricane-related volume curtailments in the Gulf of Mexico and Gulf Coast
areas of our US operations as occurred with Hurricanes Gustav and
Ike;
|
|
·
|
the
restoration of pipeline and facilities necessary to increase our Gulf of
Mexico production;
|
|
·
|
potential
winter storm-related volume curtailments in the Northern region of our US
operations;
|
|
·
|
potential
pipeline and processing facility capacity constraints in the Rocky
Mountains area of our US operations and timing of start up of a new
interstate crude oil transportation pipeline system which will run from
Weld County, Colorado to Cushing,
Oklahoma;
|
|
·
|
deliveries
of Egyptian gas in Israel, which could lower our sales
volumes;
|
|
·
|
potential
downtime at the methanol, LPG and/or LNG plants in Equatorial
Guinea;
|
|
·
|
seasonal
variations in rainfall in Ecuador that affect our natural gas-to-power
project; and
|
|
·
|
timing
of significant project completion and initial
production.
|
|
·
|
$629 million,
or 19%, increase in total revenues, due primarily to higher commodity
prices; and
|
|
·
|
$440
million gain on derivative
instruments;
|
|
·
|
$294
million impairment of assets;
|
|
·
|
$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.
|
|
·
|
$332 million,
or 11%, increase in total revenues, due primarily to higher average
realized commodity prices and an increase in income from equity method
investees; and
|
|
·
|
$394
million decrease in loss on derivative
instruments;
|
|
·
|
$208
million decrease in gains from asset
sales;
|
|
·
|
$103
million increase in DD&A
expense;
|
|
·
|
$51
million loss on involuntary conversion expense;
and
|
|
·
|
$51
million increase in oil and gas exploration
expense.
|
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
(in
millions)
|
||||||||||||
Crude
oil and condensate sales
|
$ | 2,101 | $ | 1,694 | $ | 1,489 | ||||||
Natural
gas sales
|
1,375 | 1,272 | 1,212 | |||||||||
NGL
sales (1)
|
175 | - | - | |||||||||
Total
|
$ | 3,651 | $ | 2,966 | $ | 2,701 |
(1)
|
For
2007 and 2006, US NGL sales volumes were included with natural gas
volumes. Effective in 2008, we began reporting US NGLs
separately, which has lowered the comparative natural gas sales revenues
from 2007 to 2008.
|
Average
daily sales volumes and average realized sales prices were as
follows:
|
Sales
Volumes
|
Average
Realized Sales Prices
|
|||||||||||||||||||
Crude
Oil &
|
Natural
|
Crude
Oil &
|
Natural
|
|||||||||||||||||
Condensate
|
Gas
(1)
|
NGLs
(1)
|
Condensate
|
Gas
(1)
|
NGLs
(1)
|
|||||||||||||||
(MBopd)
|
(MMcfpd)
|
(MBpd)
|
(Per
Bbl)
|
(Per
Mcf)
|
(Per
Bbl)
|
|||||||||||||||
Year
Ended December 31, 2008
|
||||||||||||||||||||
United
States (2)
|
40 | 395 | 9 | $ | 75.53 | $ | 8.12 | $ | 50.15 | |||||||||||
West
Africa (3)
|
15 | 206 | - | 88.95 | 0.27 | - | ||||||||||||||
North
Sea
|
10 | 5 | - | 100.56 | 10.54 | - | ||||||||||||||
Israel
|
- | 139 | - | - | 3.10 | - | ||||||||||||||
Ecuador
(4)
|
- | 22 | - | - | - | - | ||||||||||||||
Other
International
|
4 | - | - | 82.66 | - | - | ||||||||||||||
Total
Consolidated Operations
|
69 | 767 | 9 | 82.60 | 5.04 | 50.15 | ||||||||||||||
Equity
Investees (5)
|
2 | - | 6 | 96.77 | - | 58.81 | ||||||||||||||
Total
|
71 | 767 | 15 | $ | 82.96 | $ | 5.04 | $ | 53.45 | |||||||||||
Year
Ended December 31, 2007
|
||||||||||||||||||||
United
States (2)
|
42 | 412 | - | $ | 53.22 | $ | 7.51 | $ | - | |||||||||||
West
Africa (3)
|
15 | 132 | - | 71.27 | 0.29 | - | ||||||||||||||
North
Sea
|
13 | 6 | - | 76.47 | 6.54 | - | ||||||||||||||
Israel
|
- | 111 | - | - | 2.79 | - | ||||||||||||||
Ecuador
(4)
|
- | 26 | - | - | - | - | ||||||||||||||
Other
International
|
7 | - | - | 53.69 | - | - | ||||||||||||||
Total
Consolidated Operations
|
77 | 687 | - | 60.61 | 5.26 | - | ||||||||||||||
Equity
Investees (5)
|
2 | - | 6 | 74.87 | - | 48.87 | ||||||||||||||
Total
|
79 | 687 | 6 | $ | 60.94 | $ | 5.26 | $ | 48.87 | |||||||||||
Year
Ended December 31, 2006
|
||||||||||||||||||||
United
States (2)
|
46 | 452 | - | $ | 50.68 | $ | 6.61 | $ | - | |||||||||||
West
Africa (3)
|
18 | 45 | - | 62.51 | 0.37 | - | ||||||||||||||
North
Sea
|
4 | 8 | - | 67.43 | 8.00 | - | ||||||||||||||
Israel
|
- | 93 | - | - | 2.72 | - | ||||||||||||||
Ecuador
(4)
|
- | 25 | - | - | - | - | ||||||||||||||
Other
International
|
7 | - | - | 52.05 | - | - | ||||||||||||||
Total
Consolidated Operations
|
75 | 623 | - | 54.47 | 5.55 | - | ||||||||||||||
Equity
Investees (5)
|
2 | - | 6 | 66.60 | - | 40.10 | ||||||||||||||
Total
|
77 | 623 | 6 | $ | 54.75 | $ | 5.55 | $ | 40.10 |
(1)
|
For
2007 and 2006, US NGL sales volumes were included with natural gas
volumes. Effective in 2008, we began reporting US NGLs separately, which
has lowered the comparative natural gas sales volumes from 2007 to
2008.
|
(2)
|
Average
realized crude oil and condensate prices reflect reductions of $22.06 per
Bbl for 2008, $13.68 per Bbl for 2007, and $11.41 per Bbl for 2006 from
hedging activities. Average realized natural gas prices reflect increases
of $0.23 per Mcf for 2008 and $1.12 per Mcf for 2007, and a reduction of
$0.25 per Mcf for 2006 from hedging activities. 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 $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. We did not hedge West Africa
crude oil sales in 2006. Natural gas from the Alba field in Equatorial
Guinea is under contract for $0.25 per MMBtu to a methanol plant, an LPG
plant and an LNG plant. The methanol and LPG plants are owned by
affiliated entities accounted for under the equity method of
accounting. Natural gas volumes sold to the LNG plant totaled
163 MMcfpd in 2008 and 78 MMcfpd in 2007. The natural gas sold to the LNG
and methanol plants has a lower Btu content than the natural gas sold to
the LPG plant. As a result of the increase in natural gas volumes sold to
the LNG plant to 2008, the average price received on an Mcf basis is
lower.
|
(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
below.
|
(5)
|
Volumes
represent sales of condensate and LPG from the Alba plant in Equatorial
Guinea. See Equity Method Investees
below.
|
Year
Ended December 31,
|
||||||||||
2008
|
2007
|
2006
|
||||||||
(MBopd)
|
||||||||||
United
States
|
40 | 42 | 46 | |||||||
West
Africa
|
14 | 15 | 17 | |||||||
North
Sea
|
10 | 13 | 4 | |||||||
Other
International
|
4 | 7 | 8 | |||||||
Total
Consolidated Operations
|
68 | 77 | 75 | |||||||
Equity
Investees
|
2 | 2 | 2 | |||||||
Total
|
70 | 79 | 77 |
Year
Ended December 31,2008 (1)
|
||||||||
Crude
Oil &
|
Natural | |||||||
Condensate
|
Gas
|
|||||||
(Per
Bbl)
|
(Per
Mcf)
|
|||||||
United
States
|
$ | 71.68 | $ | 8.05 | ||||
West
Africa
|
85.98 | 0.27 | ||||||
Total
Consolidated Operations
|
79.75 | 5.00 | ||||||
Total
|
80.19 | 5.00 |
(1)
|
In
2007 and 2006 we applied cash flow hedge
accounting.
|
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
Net
income
|
(in
millions, except as noted)
|
|||||||||||
AMPCO
and affiliates
|
$ | 56 | $ | 83 | $ | 38 | ||||||
Alba
Plant
|
118 | 128 | 101 | |||||||||
Distributions/dividends
|
||||||||||||
AMPCO
and affiliates
|
65 | 97 | 37 | |||||||||
Alba
Plant
|
156 | 132 | 151 | |||||||||
Sales
volumes
|
||||||||||||
Methanol
(MMgal) (1)
|
119 | 161 | 110 | |||||||||
Condensate
(MBopd)
|
2 | 2 | 2 | |||||||||
LPG
(MBpd)
|
6 | 6 | 6 | |||||||||
Production
volumes
|
||||||||||||
Methanol
(MMgal) (1)
|
116 | 163 | 109 | |||||||||
Condensate
(MBopd)
|
2 | 2 | 2 | |||||||||
LPG
(MBpd)
|
6 | 6 | 6 | |||||||||
Average
realized prices
|
||||||||||||
Methanol
(per gallon)
|
$ | 1.25 | $ | 1.09 | $ | 0.90 | ||||||
Condensate
(per Bbl)
|
96.77 | 74.87 | 66.60 | |||||||||
LPG
(per Bbl)
|
58.81 | 48.87 | 40.10 |
(1)
|
The
variance between methanol production and sales volumes is attributable to
management’s decision to increase or decrease
inventory.
|
United
|
West
|
North
|
Other
Int'l/
|
|||||||||||||||||||||
Total
|
States
|
Africa
|
Sea
|
Israel
|
Corporate
(1)
|
|||||||||||||||||||
(in
millions)
|
||||||||||||||||||||||||
Year
Ended December 31, 2008
|
||||||||||||||||||||||||
Oil
and gas operating costs
(2)
|
$ | 333 | $ | 222 | $ | 39 | $ | 50 | $ | 9 | $ | 13 | ||||||||||||
Workover
and repair expense
|
38 | 35 | - | 3 | - | - | ||||||||||||||||||
Lease
operating expense
|
371 | 257 | 39 | 53 | 9 | 13 | ||||||||||||||||||
Production
and ad valorem taxes
|
166 | 135 | - | - | - | 31 | ||||||||||||||||||
Transportation
expense
|
57 | 49 | - | 7 | - | 1 | ||||||||||||||||||
Total
production costs
|
$ | 594 | $ | 441 | $ | 39 | $ | 60 | $ | 9 | $ | 45 | ||||||||||||
Year
Ended December 31, 2007
|
||||||||||||||||||||||||
Oil
and gas operating costs
(2)
|
$ | 299 | $ | 190 | $ | 39 | $ | 38 | $ | 8 | $ | 24 | ||||||||||||
Workover
and repair expense
|
23 | 23 | - | - | - | - | ||||||||||||||||||
Lease
operating expense
|
322 | 213 | 39 | 38 | 8 | 24 | ||||||||||||||||||
Production
and ad valorem taxes
|
114 | 91 | - | - | 23 | |||||||||||||||||||
Transportation
expense
|
52 | 40 | - | 11 | - | 1 | ||||||||||||||||||
Total
production costs
|
$ | 488 | $ | 344 | $ | 39 | $ | 49 | $ | 8 | $ | 48 | ||||||||||||
Year
Ended December 31, 2006
|
||||||||||||||||||||||||
Oil
and gas operating costs
(2)
|
$ | 270 | $ | 205 | $ | 27 | $ | 12 | $ | 9 | $ | 17 | ||||||||||||
Workover
and repair expense
|
47 | 47 | - | - | - | - | ||||||||||||||||||
Lease
operating expense
|
317 | 252 | 27 | 12 | 9 | 17 | ||||||||||||||||||
Production
and ad valorem taxes
|
109 | 86 | - | - | - | 23 | ||||||||||||||||||
Transportation
expense
|
29 | 21 | - | 7 | - | 1 | ||||||||||||||||||
Total
production costs
|
$ | 455 | $ | 359 | $ | 27 | $ | 19 | $ | 9 | $ | 41 |
(1)
|
Other
international includes Ecuador, China and Argentina (through February
2008).
|
(2)
|
Oil
and gas operating costs include labor, fuel, repairs, replacements,
saltwater disposal and other related lifting costs and exclude
depreciation of support equipment and facilities such as
vehicles.
|
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
Oil
and gas operating costs
|
$ | 4.39 | $ | 4.29 | $ | 4.14 | ||||||
Workover
and repair expense
|
0.51 | 0.33 | 0.72 | |||||||||
Lease
operating costs
|
4.90 | 4.62 | 4.86 | |||||||||
Production
and ad valorem taxes
|
2.19 | 1.63 | 1.67 | |||||||||
Transportation
expense
|
0.75 | 0.74 | 0.44 | |||||||||
Total
production costs (1)
|
$ | 7.84 | $ | 6.99 | $ | 6.97 |
(1)
|
Consolidated
unit rates exclude sales volumes and costs attributable to equity method
investees. Sales volumes include natural gas sales to an LNG plant in
Equatorial Guinea that began late first quarter of 2007. The inclusion of
these volumes reduced the unit rate by $1.19 per BOE for 2008 and $0.51
per BOE for 2007.
|
United
|
West
|
North
|
Other
Int'l/
|
|||||||||||||||||||||
Total
|
States
|
Africa
|
Sea
|
Israel
|
Corporate
(1)
|
|||||||||||||||||||
(in
millions)
|
||||||||||||||||||||||||
Year
Ended December 31, 2008
|
||||||||||||||||||||||||
Dry
hole expense
|
$ | 84 | $ | 42 | $ | 1 | $ | 8 | $ | - | $ | 33 | ||||||||||||
Seismic
|
57 | 50 | - | 4 | 3 | - | ||||||||||||||||||
Staff
expense
|
62 | 14 | 7 | 5 | 1 | 35 | ||||||||||||||||||
Other
|
14 | 13 | - | 1 | - | - | ||||||||||||||||||
Total
exploration expense
|
$ | 217 | $ | 119 | $ | 8 | $ | 18 | $ | 4 | $ | 68 | ||||||||||||
Year
Ended December 31, 2007
|
||||||||||||||||||||||||
Dry
hole expense
|
$ | 90 | $ | 50 | $ | 40 | $ | - | $ | - | $ | - | ||||||||||||
Seismic
|
65 | 55 | 1 | 8 | 1 | - | ||||||||||||||||||
Staff
expense
|
46 | 12 | 2 | 9 | 1 | 22 | ||||||||||||||||||
Other
|
18 | 17 | - | - | - | 1 | ||||||||||||||||||
Total
exploration expense
|
$ | 219 | $ | 134 | $ | 43 | $ | 17 | $ | 2 | $ | 23 | ||||||||||||
Year
Ended December 31, 2006
|
||||||||||||||||||||||||
Dry
hole expense
|
$ | 70 | $ | 66 | $ | - | $ | 4 | $ | - | $ | - | ||||||||||||
Seismic
|
38 | 29 | 4 | 1 | - | 4 | ||||||||||||||||||
Staff
expense
|
39 | 13 | 3 | 5 | - | 18 | ||||||||||||||||||
Other
|
21 | 20 | - | 1 | - | - | ||||||||||||||||||
Total
exploration expense
|
$ | 168 | $ | 128 | $ | 7 | $ | 11 | $ | - | $ | 22 |
(1)
|
Other
international includes Ecuador, China, Argentina (through February 2008),
Suriname and other international new
ventures.
|
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
(in
millions)
|
||||||||||||
United
States
|
$ | 646 | $ | 580 | $ | 552 | ||||||
West
Africa
|
34 | 25 | 24 | |||||||||
North
Sea
|
55 | 81 | 9 | |||||||||
Israel
|
24 | 18 | 14 | |||||||||
Other
international, corporate, and other
|
32 | 32 | 34 | |||||||||
Total
DD&A expense (1)
|
$ | 791 | $ | 736 | $ | 633 | ||||||
Unit
rate of DD&A per BOE (2)
|
$ | 10.44 | $ | 10.55 | $ | 9.71 |
(1)
|
DD&A
expense includes accretion of discount on asset retirement obligations of
$10 million in 2008, $8 million in 2007, and $11 million in
2006.
|
(2)
|
Consolidated
unit rates exclude sales volumes and costs
attributable to equity method investees. Sales
volumes include natural gas sales to an LNG plant in Equatorial Guinea
that began late first quarter of 2007. The inclusion of these volumes
reduced the unit rate by $1.29 per BOE for 2008 and $0.63 per BOE for
2007.
|
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
G&A
expense (in millions)
|
$ | 236 | $ | 206 | $ | 165 | ||||||
Unit
rate per BOE
(1)
|
$ | 3.12 | $ | 2.96 | $ | 2.52 |
(1)
|
Consolidated
unit rates exclude sales volumes and costs attributable to equity method
investees. Sales volumes include natural gas sales to an LNG plant in
Equatorial Guinea that began late first quarter of 2007. The inclusion of
these volumes reduced the unit rate by $0.47 per BOE for 2008 and $0.21
per BOE for 2007.
|
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
(in
millions, except as noted)
|
||||||||||||
Electricity
sales
|
$ | 56 | $ | 71 | $ | 72 | ||||||
Electricity
generation expense
|
57 | 57 | 59 | |||||||||
Operating
income
|
(1 | ) | 14 | 13 | ||||||||
Power
generation (GW)
|
749 | 912 | 866 | |||||||||
Average
power price ($/Kwh)
|
$ | 0.074 | $ | 0.078 | $ | 0.083 |
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
(in
millions)
|
||||||||||||
Interest
expense
|
$ | 102 | $ | 130 | $ | 130 | ||||||
Capitalized
interest
|
(33 | ) | (17 | ) | (13 | ) | ||||||
Interest
expense, net
|
$ | 69 | $ | 113 | $ | 117 |
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
Income
tax provision (in millions)
|
$ | 711 | $ | 424 | $ | 418 | ||||||
Effective
rate
|
34.5 | % | 31.0 | % | 38.1 | % |
Summary
cash flow information is as
follows:
|
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
(in millions) | ||||||||||||
Total
cash provided by (used in):
|
||||||||||||
Operating
activities
|
$ | 2,285 | $ | 2,017 | $ | 1,730 | ||||||
Investing
activities
|
(2,132 | ) | (1,403 | ) | (1,098 | ) | ||||||
Financing
activities
|
327 | (107 | ) | (589 | ) | |||||||
Increase
in cash and cash equivalents
|
$ | 480 | $ | 507 | $ | 43 |
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
(in
millions)
|
||||||||||||
Acquisition,
Capital and Other Exploration Expenditures
|
||||||||||||
Unproved
property acquisition (1)
|
$ | 303 | $ | 145 | $ | 185 | ||||||
Proved
property acquisition (2)
|
255 | 11 | 523 | |||||||||
Exploration
expenditures
|
448 | 372 | 203 | |||||||||
Development
expenditures
|
1,193 | 1,175 | 1,055 | |||||||||
Corporate
and other expenditures
|
65 | 36 | 35 | |||||||||
Total
expenditures
|
2,264 | 1,739 | 2,001 |
(1)
|
Unproved
property acquisition cost for 2008 includes $179 million for deepwater
Gulf of Mexico lease blocks, $38 million related to the Mid-continent
acquisition, $80 million related to additional onshore US lease
acquisitions and $6 million related to international lease acquisitions.
Unproved property acquisition cost for 2006 includes $131 million
allocated to properties acquired in the U.S. Exploration
acquisition.
|
(2)
|
Proved
property acquisition cost for 2008 includes $254 million related to the
Mid-continent acquisition. Proved property acquisition cost for 2006
includes $413 million allocated to properties acquired in the U.S.
Exploration acquisition.
|
|
·
|
$1.4 billion
increase in shareholders’ equity from current year net
income;
|
|
·
|
$390 million
increase in total debt from the balance at December 31, 2007;
and
|
|
·
|
$115
million decrease in shareholders’ equity from dividends
paid.
|
Payments
Due by Period
|
||||||||||||||||||||
2010
|
2012
|
2014
and
|
||||||||||||||||||
Total
|
2009
|
and
2011
|
and
2013
|
Beyond
|
||||||||||||||||
(in
millions)
|
||||||||||||||||||||
Long-term
debt (excluding interest) (1)
|
$ | 2,270 | $ | 25 | $ | - | $ | 1,606 | $ | 639 | ||||||||||
Drilling
and equipment obligations: (2)
|
||||||||||||||||||||
United
States
|
752 | 70 | 613 | 69 | - | |||||||||||||||
International
|
480 | 252 | 225 | 3 | - | |||||||||||||||
Purchase
obligations (3)
|
163 | 163 | - | - | - | |||||||||||||||
Throughput
agreement (4)
|
95 | 14 | 38 | 38 | 5 | |||||||||||||||
Transportation
and gathering (5)
|
43 | 12 | 17 | 10 | 4 | |||||||||||||||
Operating
lease obligations (6)
|
56 | 12 | 18 | 8 | 18 | |||||||||||||||
Other
long-term liabilities: (7)
|
||||||||||||||||||||
Asset
retirement obligations (8)
|
211 | 27 | 18 | 29 | 137 | |||||||||||||||
Commodity
derivative instruments (9)
|
25 | 23 | 2 | - | - | |||||||||||||||
Total
contractual obligations
|
$ | 4,095 | $ | 598 | $ | 931 | $ | 1,763 | $ | 803 |
(1)
|
Based
on the total debt balance, scheduled maturities and interest rates in
effect at December 31, 2008, our cash payments for interest would be
$58 million in 2009, $57 million in 2010, $57 million in 2011,
$56 million in 2012, $44 million in 2013 and $878 million for the
remaining years for a total of $1.2 billion. See Item 8. Financial
Statements and Supplementary Data—Note
8—Debt.
|
(2)
|
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.
|
(3)
|
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.
|
(4)
|
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 is expected to become operational in 2009. See
Item 8. Financial Statements and Supplementary Data—Note
17—Commitments and Contingencies.
|
(5) |
Transportation
and gathering obligations represent minimum changes for our firm
transportation and gathering agreements. See Item 8. Financial Statements
and Supplementary Data —Note 17—Commitments and
Contingencies.
|
(6)
|
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.
|
(7)
|
The
table excludes deferred compensation liabilities of $159 million and
accrued benefit costs of $81 million as specific payment dates are
unknown. See Item 8. Financial Statements and Supplementary Data—Note 12—Benefit
Plans.
|
(8)
|
Asset
retirement obligations are discounted. See Item 8. Financial Statements
and Supplementary Data—Note 10—Asset Retirement
Obligations.
|
(9)
|
Amount
represents open commodity derivative instruments that were in a net
payable position with the counterparty at December 31, 2008. Our remaining
commodity derivative instruments were in a net receivable position at
December 31, 2008. 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.
|
|
57
|
|
58
|
|
59
|
|
60
|
|
61
|
|
62
|
|
63
|
|
64
|
|
65
|
|
97
|
|
107
|
|
Noble
Energy, Inc.
|
Noble
Energy, Inc. and Subsidiaries
|
||||||||||||
(in
millions, except per share amounts)
|
||||||||||||
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
Revenues
|
||||||||||||
Oil,
gas and NGL sales
|
$ | 3,651 | $ | 2,966 | $ | 2,701 | ||||||
Income
from equity method investees
|
174 | 211 | 139 | |||||||||
Other
revenues
|
76 | 95 | 100 | |||||||||
Total
|
3,901 | 3,272 | 2,940 | |||||||||
Costs
and Expenses
|
||||||||||||
Lease
operating expense
|
371 | 322 | 317 | |||||||||
Production
and ad valorem taxes
|
166 | 114 | 109 | |||||||||
Transportation
expense
|
57 | 52 | 29 | |||||||||
Exploration
expense
|
217 | 219 | 168 | |||||||||
Depreciation,
depletion and amortization
|
791 | 736 | 633 | |||||||||
General
and administrative
|
236 | 206 | 165 | |||||||||
Asset
impairments
|
294 | 4 | 9 | |||||||||
Gain
on sale of assets
|
(5 | ) | (12 | ) | (220 | ) | ||||||
Other
operating expense, net
|
129 | 145 | 111 | |||||||||
Total
|
2,256 | 1,786 | 1,321 | |||||||||
Operating
Income
|
1,645 | 1,486 | 1,619 | |||||||||
Other
(Income) Expense
|
||||||||||||
(Gain)
loss on commodity derivative instruments
|
(440 | ) | (2 | ) | 392 | |||||||
Interest,
net of amount capitalized
|
69 | 113 | 117 | |||||||||
Other
(income) expense, net
|
(45 | ) | 7 | 14 | ||||||||
Total
|
(416 | ) | 118 | 523 | ||||||||
Income
Before Income Taxes
|
2,061 | 1,368 | 1,096 | |||||||||
Income
Tax Provision
|
711 | 424 | 418 | |||||||||
Net
Income
|
$ | 1,350 | $ | 944 | $ | 678 | ||||||
Earnings
Per Share
|
||||||||||||
Basic
|
$ | 7.83 | $ | 5.52 | $ | 3.86 | ||||||
Diluted
|
7.58 | 5.45 | 3.79 | |||||||||
Weighted
average number of shares outstanding
|
||||||||||||
Basic
|
173 | 171 | 176 | |||||||||
Diluted
|
176 | 173 | 179 | |||||||||
The
accompanying notes are an integral part of these financial
statements.
|
Noble
Energy, Inc. and Subsidiaries
|
||||||||
(in
millions)
|
||||||||
December
31,
|
||||||||
2008
|
2007
|
|||||||
ASSETS
|
||||||||
Current
Assets
|
||||||||
Cash
and cash equivalents
|
$ | 1,140 | $ | 660 | ||||
Accounts
receivable, net
|
423 | 594 | ||||||
Commodity
derivative instruments
|
437 | 15 | ||||||
Deferred
income taxes
|
- | 131 | ||||||
Asset
held for sale
|
26 | 82 | ||||||
Other
current assets
|
132 | 87 | ||||||
Total
current assets
|
2,158 | 1,569 | ||||||
Property,
plant and equipment:
|
||||||||
Oil
and gas properties (successful efforts method of
accounting)
|
11,963 | 10,217 | ||||||
Other
property, plant and equipment
|
175 | 112 | ||||||
Total
property, plant and equipment, net
|
12,138 | 10,329 | ||||||
Accumulated
depreciation, depletion and amortization
|
(3,134 | ) | (2,384 | ) | ||||
Total
property, plant and equipment, net
|
9,004 | 7,945 | ||||||
Goodwill
|
759 | 761 | ||||||
Other
noncurrent assets
|
463 | 556 | ||||||
Total
Assets
|
$ | 12,384 | $ | 10,831 | ||||
LIABILITIES
AND SHAREHOLDERS’ EQUITY
|
||||||||
Current
Liabilities
|
||||||||
Accounts
payable - trade
|
$ | 579 | $ | 781 | ||||
Income
taxes payable
|
130 | 52 | ||||||
Commodity
derivative instruments
|
23 | 540 | ||||||
Deferred
income taxes
|
142 | - | ||||||
Other
current liabilities
|
300 | 263 | ||||||
Total
current liabilities
|
1,174 | 1,636 | ||||||
Long-term
debt
|
2,241 | 1,851 | ||||||
Deferred
income taxes
|
2,174 | 1,984 | ||||||
Other
noncurrent liabilities
|
486 | 551 | ||||||
Total
Liabilities
|
6,075 | 6,022 | ||||||
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;
|
||||||||
192
million and 191 million shares issued, respectively
|
641 | 636 | ||||||
Capital
in excess of par value
|
2,193 | 2,106 | ||||||
Accumulated
other comprehensive loss
|
(110 | ) | (284 | ) | ||||
Treasury
stock, at cost: 19 million shares
|
(614 | ) | (613 | ) | ||||
Retained
earnings
|
4,199 | 2,964 | ||||||
Total
Shareholders’ Equity
|
6,309 | 4,809 | ||||||
Total
Liabilities and Shareholders’ Equity
|
$ | 12,384 | $ | 10,831 | ||||
The
accompanying notes are an integral part of these financial
statements.
|
Noble
Energy, Inc. and Subsidiaries
|
||||||||||||
(in
millions)
|
||||||||||||
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
Cash
Flows from Operating Activities
|
||||||||||||
Net
income
|
$ | 1,350 | $ | 944 | $ | 678 | ||||||
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
||||||||||||
Depreciation,
depletion and amortization
|
791 | 736 | 633 | |||||||||
Dry
hole expense
|
84 | 90 | 70 | |||||||||
Impairment
of assets
|
294 | 4 | 9 | |||||||||
Gain
on sale of assets
|
(5 | ) | (12 | ) | (220 | ) | ||||||
Deferred
income taxes
|
359 | 292 | 194 | |||||||||
Income
from equity method investees
|
(174 | ) | (211 | ) | (139 | ) | ||||||
Dividends
from equity method investees
|
221 | 227 | 37 | |||||||||
Unrealized
(gain) loss on commodity derivative instruments
|
(522 | ) | (2 | ) | 9 | |||||||
Settlement
of previously recognized hedge losses
|
(194 | ) | (183 | ) | 406 | |||||||
Allowance
for doubtful accounts
|
49 | 14 | 19 | |||||||||
Loss
on involuntary conversion
|
9 | 51 | - | |||||||||
Other
|
26 | 91 | 82 | |||||||||
Changes
in operating assets and liabilities, net of acquisition:
|
||||||||||||
Decrease
(increase) in accounts receivable
|
121 | (22 | ) | (32 | ) | |||||||
(Increase)
decrease in other current assets
|
(37 | ) | 8 | (5 | ) | |||||||
Decrease
in probable insurance claims
|
20 | 108 | 140 | |||||||||
(Decrease)
increase in accounts payable
|
(142 | ) | 19 | (11 | ) | |||||||
Increase
(decrease) in other current liabilities
|
35 | (137 | ) | (140 | ) | |||||||
Net
Cash Provided by Operating Activities
|
2,285 | 2,017 | 1,730 | |||||||||
Cash
Flows From Investing Activities
|
||||||||||||
Additions
to property, plant and equipment
|
(1,971 | ) | (1,414 | ) | (1,357 | ) | ||||||
Acquisitions,
net of cash acquired
|
(292 | ) | - | (412 | ) | |||||||
Proceeds
from sale of property, plant and equipment
|
131 | 9 | 520 | |||||||||
Distributions
from equity method investees, net
|
- | 2 | 151 | |||||||||
Net
Cash Used in Investing Activities
|
(2,132 | ) | (1,403 | ) | (1,098 | ) | ||||||
Cash
Flows From Financing Activities
|
||||||||||||
Exercise
of stock options
|
27 | 25 | 63 | |||||||||
Excess
tax benefits from stock-based awards
|
24 | 20 | 26 | |||||||||
Cash
dividends paid
|
(115 | ) | (75 | ) | (49 | ) | ||||||
Purchase
of treasury stock
|
(3 | ) | (102 | ) | (399 | ) | ||||||
Proceeds
from credit facilities
|
951 | 280 | 480 | |||||||||
Repayment
of credit facilities
|
(525 | ) | (255 | ) | (605 | ) | ||||||
Repurchase
of senior debentures
|
(7 | ) | - | - | ||||||||
Repayment
of installment notes
|
(25 | ) | - | - | ||||||||
Repayment
of term loans
|
- | - | (105 | ) | ||||||||
Net
Cash Provided by (Used in) Financing Activities
|
327 | (107 | ) | (589 | ) | |||||||
Increase
in Cash and Cash Equivalents
|
480 | 507 | 43 | |||||||||
Cash
and Cash Equivalents at Beginning of Period
|
660 | 153 | 110 | |||||||||
Cash
and Cash Equivalents at End of Period
|
$ | 1,140 | $ | 660 | $ | 153 | ||||||
The
accompanying notes are an integral part of these financial
statements.
|
||||||||||||
Noble
Energy, Inc. and Subsidiaries
|
||||||||||||
(in
millions)
|
||||||||||||
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
Common
Stock
|
||||||||||||
Balance,
beginning of year
|
$ | 636 | $ | 629 | $ | 616 | ||||||
Exercise
of stock options
|
4 | 5 | 13 | |||||||||
Restricted
stock awards, net
|
1 | 2 | - | |||||||||
Balance,
end of year
|
641 | 636 | 629 | |||||||||
Capital
in Excess of Par Value
|
||||||||||||
Balance,
beginning of year
|
2,106 | 2,041 | 1,945 | |||||||||
Stock-based
compensation expense
|
39 | 27 | 12 | |||||||||
Exercise
of stock options
|
23 | 20 | 50 | |||||||||
Tax
benefits related to exercise of stock options
|
24 | 20 | 26 | |||||||||
Restricted
stock awards, net
|
(1 | ) | (2 | ) | - | |||||||
Rabbi
trust shares sold
|
2 | - | 13 | |||||||||
Adoption
of SFAS 123(R), net of tax
|
- | - | (5 | ) | ||||||||
Balance,
end of year
|
2,193 | 2,106 | 2,041 | |||||||||
Accumulated
Other Comprehensive Loss
|
||||||||||||
Balance,
beginning of year
|
(284 | ) | (140 | ) | (784 | ) | ||||||
Oil
and gas cash flow hedges:
|
||||||||||||
Realized
amounts reclassified into earnings
|
207 | 33 | 145 | |||||||||
Unrealized
amounts reclassified into earnings
|
- | - | 265 | |||||||||
Unrealized
change in fair value
|
- | (184 | ) | 250 | ||||||||
Net
change in other
|
(33 | ) | 7 | 17 | ||||||||
Adoption
of SFAS 158, net of tax
|
- | - | (33 | ) | ||||||||
Balance,
end of year
|
(110 | ) | (284 | ) | (140 | ) | ||||||
Treasury
Stock at Cost
|
||||||||||||
Balance,
beginning of year
|
(613 | ) | (511 | ) | (148 | ) | ||||||
Purchases
of treasury stock
|
(3 | ) | (102 | ) | (399 | ) | ||||||
Rabbi
trust shares sold
|
2 | - | 36 | |||||||||
Balance,
end of year
|
(614 | ) | (613 | ) | (511 | ) | ||||||
Deferred
Compensation - Restricted Stock
|
||||||||||||
Balance,
beginning of year
|
- | - | (5 | ) | ||||||||
Adoption
of SFAS 123(R), net of tax
|
- | - | 5 | |||||||||
Balance,
end of year
|
- | - | - | |||||||||
Retained
Earnings
|
||||||||||||
Balance,
beginning of year
|
2,964 | 2,095 | 1,466 | |||||||||
Net
income
|
1,350 | 944 | 678 | |||||||||
Cash
dividends ($0.660, $0.435, and $0.275 per share,
respectively)
|
(115 | ) | (75 | ) | (49 | ) | ||||||
Balance,
end of year
|
4,199 | 2,964 | 2,095 | |||||||||
Total
Shareholders' Equity
|
$ | 6,309 | $ | 4,809 | $ | 4,114 | ||||||
The
accompanying notes are an integral part of these financial
statements.
|
Noble
Energy, Inc. and Subsidiaries
|
||||||||||||
(in
millions)
|
||||||||||||
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
Net
income
|
$ | 1,350 | $ | 944 | $ | 678 | ||||||
Other
items of comprehensive income (loss)
|
||||||||||||
Oil
and gas cash flow hedges:
|
||||||||||||
Realized
amounts reclassified into earnings
|
331 | 54 | 232 | |||||||||
Less
tax provision
|
(124 | ) | (21 | ) | (87 | ) | ||||||
Unrealized
change in fair value
|
- | (295 | ) | 352 | ||||||||
Less
tax provision
|
- | 111 | (102 | ) | ||||||||
Unrealized
amounts reclassified into earnings
|
- | - | 424 | |||||||||
Less
tax provision
|
- | - | (159 | ) | ||||||||
Net
change in other
|
(52 | ) | 11 | 25 | ||||||||
Less
tax provision
|
19 | (4 | ) | (8 | ) | |||||||
Other
comprehensive income (loss)
|
174 | (144 | ) | 677 | ||||||||
Comprehensive
income
|
$ | 1,524 | $ | 800 | $ | 1,355 | ||||||
The
accompanying notes are an integral part of these financial
statements.
|
Year
Ended December 31,
|
||||||||
2008
|
2007
|
|||||||
(in
millions)
|
||||||||
Balance,
beginning of period
|
$ | 761 | $ | 781 | ||||
Tax
adjustments related to acquisitions
|
- | (15 | ) | |||||
Tax
benefits on stock options exercised
|
(2 | ) | (5 | ) | ||||
Balance,
end of period
|
$ | 759 | $ | 761 |
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
(in
millions)
|
||||||||||||
Other
Revenues
|
||||||||||||
Electricity
sales (1)
|
$ | 56 | $ | 71 | $ | 72 | ||||||
Gathering,
marketing and processing
|
20 | 24 | 28 | |||||||||
Total
|
$ | 76 | $ | 95 | $ | 100 | ||||||
Other
Operating Expense, net
|
||||||||||||
Electricity
generation(1)
|
$ | 57 | $ | 57 | $ | 59 | ||||||
Gathering,
marketing and processing
|
19 | 17 | 19 | |||||||||
Loss
on involuntary conversion of assets (2)
|
9 | 51 | - | |||||||||
Other
operating (income) expense, net (3)
|
44 | 20 | 33 | |||||||||
Total
|
$ | 129 | $ | 145 | $ | 111 | ||||||
Other
Expense, net
|
||||||||||||
Deferred
compensation (income) expense (4)
|
$ | (32 | ) | $ | 33 | $ | 16 | |||||
Interest
income
|
(20 | ) | (19 | ) | (3 | ) | ||||||
Other
(income) expense, net
|
7 | (7 | ) | 1 | ||||||||
Total
|
$ | (45 | ) | $ | 7 | $ | 14 |
(1)
|
Includes amounts
related to our 100%-owned Ecuador integrated power project. The
project includes the Amistad natural gas field, offshore Ecuador, which
supplies natural gas to fuel the Machala power plant located in Machala,
Ecuador. Electricity generation expense includes DD&A and increases in
the allowance for doubtful accounts of $11 million in 2008, $14 million in
2007 and $15 million in 2006. See Allowance for Doubtful
Accounts below.
|
(2)
|
See
Note 4 – Acquisitions and Divestitures – Main Pass
Asset.
|
(3)
|
Includes
$38 million write-down of SemCrude, L.P. receivable in third quarter 2008.
See Note 17 – Commitments and
Contingencies.
|
(4)
|
Amount
represents increases (decreases) in the fair value of Noble Energy common
stock held in a rabbi trust. See Note 12 – Benefit
Plans.
|
Balance Sheet Information –
Additional balance sheet information is as
follows:
|
December
31,
|
||||||||
2008
|
2007
|
|||||||
(in
millions)
|
||||||||
Other
Current Assets
|
||||||||
Inventories
|
$ | 105 | $ | 60 | ||||
Prepaid
expenses and other
|
27 | 27 | ||||||
Total
|
$ | 132 | $ | 87 | ||||
Other
Noncurrent Assets
|
||||||||
Equity
method investments
|
$ | 311 | $ | 357 | ||||
Mutual
fund investments
|
84 | 124 | ||||||
Commodity
derivative instruments
|
33 | 5 | ||||||
Other
assets
|
35 | 70 | ||||||
Total
|
$ | 463 | $ | 556 | ||||
Other
Current Liabilities
|
||||||||
Accrued
and other current liabilities
|
$ | 215 | $ | 207 | ||||
Short-term
borrowings
|
25 | 25 | ||||||
Asset
retirement obligations
|
27 | 13 | ||||||
Interest
payable
|
9 | 18 | ||||||
Deferred
gain on asset sale
|
24 | - | ||||||
Total
|
$ | 300 | $ | 263 | ||||
Other
Noncurrent Liabilities
|
||||||||
Deferred
compensation liabilities
|
$ | 159 | $ | 225 | ||||
Commodity
derivative instruments
|
2 | 83 | ||||||
Asset
retirement obligations
|
184 | 131 | ||||||
Accrued
benefit costs
|
81 | 51 | ||||||
Other
noncurrent liabilities
|
60 | 61 | ||||||
Total
|
$ | 486 | $ | 551 |
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
(in
millions)
|
||||||||||||
Cash
paid during the year for
|
||||||||||||
Interest,
net of amount capitalized
|
$ | 76 | $ | 105 | $ | 106 | ||||||
Income
taxes paid, net
|
263 | 149 | 115 | |||||||||
Non-cash
financing and investing activities
|
||||||||||||
Issuance
of notes for property interests
|
- | 50 | - |
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
(in
millions)
|
||||||||||||
Balance,
beginning of period
|
$ | 50 | $ | 35 | $ | 19 | ||||||
Charged
to expense
|
49 | 14 | 19 | |||||||||
Deductions
and other
|
(2 | ) | 1 | (3 | ) | |||||||
Balance,
end of period
|
$ | 97 | $ | 50 | $ | 35 |
December
31,
|
||||||||
2008
|
2007
|
|||||||
(in
millions)
|
||||||||
Materials
and supplies
|
$ | 92 | $ | 56 | ||||
Crude
oil
|
13 | 4 | ||||||
Total
inventories
|
$ | 105 | $ | 60 |
Note
3 – Asset
Impairments
|
Note 4—Acquisitions and
Divestitures
|
|
·
|
$413 million
to proved oil and gas properties;
|
|
·
|
$131 million
to unproved oil and gas properties;
|
|
·
|
$34 million
to goodwill; and
|
|
·
|
$172 million
to deferred income taxes.
|
Fair
Value Measurements Using
|
||||||||||||||||
Quoted
Prices
|
Significant
Other
|
Significant
|
|
|
||||||||||||
in
Active
|
Observable
|
Unobservable
|
Fair
|
|||||||||||||
Markets
|
Inputs
|
Inputs
|
Netting |
Value
|
||||||||||||
(Level
1)
|
(Level
2)
|
(Level
3)
|
Adjustment
(1)
|
Measurement
|
||||||||||||
(in
millions)
|
||||||||||||||||
Financial
assets
|
||||||||||||||||
Mutual
fund investments
|
$ |
84
|
$ |
-
|
$ |
-
|
$ |
-
|
$ |
84
|
||||||
Commodity
derivative instruments
|
-
|
492
|
-
|
(22
|
) |
470
|
||||||||||
Financial
liabilities
|
||||||||||||||||
Commodity
derivative instruments
|
-
|
(47
|
) |
-
|
22
|
(25
|
)
|
(1)
|
Amount
represents the impact of master netting agreements that allow us to settle
asset and liability positions with the same
counterparty.
|
December
31,
|
|||||||||||
2008
|
2007
|
||||||||||
Carrying
|
Fair
|
Carrying
|
Fair
|
||||||||
Amount
|
Value
|
Amount
|
Value
|
||||||||
(in
millions)
|
|||||||||||
Total
debt, net of unamortized discount
|
$ |
2,266
|
$
|
2,172
|
$ |
1,876
|
$ |
1,920
|
Note
6—Derivative Instruments and Hedging
Activities
|
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
(in
millions)
|
||||||||||||
Unrealized
gain on commodity derivative instruments
|
$ | (522 | ) | $ | - | $ | - | |||||
Realized
(gain) loss on commodity derivative instruments
|
82 | - | (41 | ) | ||||||||
Reclassified
from AOCL (1)
|
- | - | 424 | |||||||||
Ineffectiveness
(gain) loss
|
- | (2 | ) | 9 | ||||||||
(Gain)
loss on commodity derivative instruments
|
$ | (440 | ) | $ | (2 | ) | $ | 392 |
(1)
|
Under
our previous cash flow hedge accounting, if it became probable that the
hedging instrument was no longer highly effective, the hedging instrument
lost hedge accounting treatment. All current mark-to-market gains and
losses were recorded in earnings and all accumulated gains or losses
recorded in AOCL related to the hedging instrument were also reclassified
to earnings. During 2006, we reclassified a pretax charge of $399 million
from AOCL to earnings when it became probable that forecasted crude oil
and natural gas sales would not occur due to the sale of Gulf of Mexico
shelf properties. A mark-to-market gain of $39 million and the
reclassification of a pretax charge of $25 million from AOCL to earnings
due to the impacts of Hurricanes Katrina and Rita on the timing of
forecasted Gulf of Mexico production were also included in
2006.
|
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
(in
millions)
|
||||||||||||
(Decrease)
in crude oil sales
|
$ | (365 | ) | $ | (223 | ) | $ | (191 | ) | |||
Increase
(decrease) in natural gas sales
|
34 | 169 | (41 | ) | ||||||||
Total
(decrease) in crude oil and natural gas sales
|
$ | (331 | ) | $ | (54 | ) | $ | (232 | ) |
Variable
to Fixed Price Swaps
|
Costless
Collars
|
|||||||||||||||||
Weighted
|
Weighted
|
Weighted
|
||||||||||||||||
Production
|
Bbls
|
Average
|
Bbls
|
Average
|
Average
|
|||||||||||||
Period
|
Index
|
Per
Day
|
Fixed
Price
|
Index
|
Per
Day
|
Floor
Price
|
Ceiling
Price
|
|||||||||||
2009
|
NYMEX
WTI
|
9,000
|
$ |
88.43
|
NYMEX
WTI
|
6,700
|
$ |
79.70
|
$ |
90.60
|
||||||||
2009
|
Dated
Brent
|
2,000
|
87.98
|
Dated
Brent
|
5,074
|
70.62
|
87.93
|
|||||||||||
2009
Average
|
11,000
|
88.35
|
11,774
|
75.79
|
89.45
|
|||||||||||||
2010
|
NYMEX
WTI
|
5,500
|
69.00
|
85.65
|
Costless
Collars
|
|||||||||||
Weighted
|
Weighted
|
||||||||||
Production
|
MMBtu
|
Average
|
Average
|
||||||||
Period
|
Index
|
Per
Day
|
Floor
Price
|
Ceiling
Price
|
|||||||
2009
|
NYMEX
HH
|
170,000
|
$
|
9.15
|
$ |
10.81
|
|||||
2009
|
IFERC
CIG (1)
|
15,000
|
6.00
|
9.90
|
|||||||
2009
Average
|
185,000
|
8.90
|
10.73
|
||||||||
2010
|
IFERC
CIG
|
15,000
|
6.25
|
8.10
|
(1)
|
Colorado
Interstate Gas – Northern System
|
Basis
Swaps
|
||||||||||||
Weighted
|
||||||||||||
Production
|
Index
Less
|
MMBtu
|
Average
|
|||||||||
Period
|
Index
|
Differential
|
Per
Day
|
Differential
|
||||||||
2009
|
IFERC
CIG
|
NYMEX
HH
|
140,000 | $ | 2.49 | |||||||
2010
|
IFERC
CIG
|
NYMEX
HH
|
20,000 | 1.99 |
December
31,
|
||||||||
2008
|
2007
|
|||||||
(in
millions)
|
||||||||
Commodity
derivative instruments
|
||||||||
Current
asset
|
$ | 437 | $ | 15 | ||||
Long-term
asset
|
33 | 5 | ||||||
Current
liability
|
(23 | ) | (540 | ) | ||||
Long-term
liability
|
(2 | ) | (83 | ) |
Note
7—Capitalized Exploratory Well
Costs
|
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
(in
millions)
|
||||||||||||
Capitalized
exploratory well costs, beginning of period
|
$ | 249 | $ | 80 | $ | 35 | ||||||
Additions to
capitalized exploratory well costs pending determination of proved
reserves
|
253 | 182 | 63 | |||||||||
Reclassified to
proved oil and gas properties based on determination of proved
reserves
|
- | (7 | ) | (17 | ) | |||||||
Capitalized
exploratory well costs charged to expense
|
(1 | ) | (6 | ) | (1 | ) | ||||||
Capitalized
exploratory well costs, end of period
|
$ | 501 | $ | 249 | $ | 80 |
December
31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
(in
millions)
|
||||||||||||
Exploratory
well costs capitalized for a period of one year or less
|
$ | 256 | $ | 187 | $ | 58 | ||||||
Exploratory well
costs capitalized for a period greater than one year after
completion of drilling
|
245 | 62 | 22 | |||||||||
Balance,
end of period
|
$ | 501 | $ | 249 | $ | 80 | ||||||
Number
of projects with exploratory well costs that have been capitalized
for a period greater than one year after completion of
drilling
|
6 | 5 | 4 |
Suspended Since | ||||||||||||||||
Total
|
2007
|
2006
|
2005
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Project
|
||||||||||||||||
West
Africa
|
$ | 160 | $ | 140 | $ | 1 | $ | 19 | ||||||||
Raton
South (deepwater Gulf of Mexico)
|
28 | 5 | 23 | - | ||||||||||||
Redrock
(deepwater Gulf of Mexico)
|
17 | - | 17 | - | ||||||||||||
Flyndre
(North Sea)
|
15 | 12 | 3 | - | ||||||||||||
Selkirk
(North Sea)
|
22 | 22 | - | - | ||||||||||||
Other
|
3 | - | 3 | - | ||||||||||||
Total exploratory
well costs capitalized for a period greater than one year after
completion of drilling
|
$ | 245 | $ | 179 | $ | 47 | $ | 19 |
December
31,
|
||||||||||||||
2008
|
2007
|
|||||||||||||
Debt
|
Interest
Rate
|
Debt
|
Interest
Rate
|
|||||||||||
(in
millions, except percentages)
|
||||||||||||||
Credit
facility
|
$ | 1,606 | 0.80 | % | $ | 1,180 | 5.28 | % | ||||||
5
¼% Senior Notes, due April 15, 2014
|
200 | 5.25 | % | 200 | 5.25 | % | ||||||||
7
¼% Notes, due October 15, 2023
|
100 | 7.25 | % | 100 | 7.25 | % | ||||||||
8%
Senior Notes, due April 1, 2027
|
250 | 8.00 | % | 250 | 8.00 | % | ||||||||
7
¼% Senior Debentures, due August 1, 2097
|
89 | 7.25 | % | 100 | 7.25 | % | ||||||||
Installment
payments, due May 11, 2009
|
- | - | 25 | 5.53 | % | |||||||||
Long-term
debt
|
2,245 | 1,855 | ||||||||||||
Installment
payments - current portion
|
25 | 4.18 | % | 25 | 5.53 | % | ||||||||
Total
debt
|
2,270 | 1,880 | ||||||||||||
Unamortized
discount
|
(4 | ) | (4 | ) | ||||||||||
Total
debt, net of discount
|
$ | 2,266 | $ | 1,876 |
(in
millions)
|
||||
2009
|
$ | 25 | ||
2010
|
- | |||
2011
|
- | |||
2012
|
1,606 | |||
2013
|
- | |||
Thereafter
|
639 | |||
Total
|
$ | 2,270 |
Note
9—Income Taxes
|
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
(in
millions)
|
||||||||||||
Domestic
|
$ | 1,032 | $ | 480 | $ | 402 | ||||||
Foreign
|
1,029 | 888 | 694 | |||||||||
Total
|
$ | 2,061 | $ | 1,368 | $ | 1,096 |
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
(in
millions)
|
||||||||||||
Current
taxes
|
||||||||||||
Federal
|
$ | 45 | $ | 6 | $ | 80 | ||||||
State
|
1 | 1 | 6 | |||||||||
Foreign
|
306 | 125 | 138 | |||||||||
Total
current
|
352 | 132 | 224 | |||||||||
Deferred
taxes
|
||||||||||||
Federal
|
363 | 186 | 144 | |||||||||
State
|
4 | 6 | 5 | |||||||||
Foreign
|
(8 | ) | 100 | 45 | ||||||||
Total
deferred
|
359 | 292 | 194 | |||||||||
Total
income tax provision
|
$ | 711 | $ | 424 | $ | 418 |
Year
Ended December 31,
|
||||||||||
2008
|
2007
|
2006
|
||||||||
(amounts
in percentages)
|
||||||||||
Federal
statutory rate
|
35.0 | 35.0 | 35.0 | |||||||
Effect
of
|
||||||||||
Earnings
of equity method investees
|
(2.9 | ) | (5.4 | ) | (4.2 | ) | ||||
State
taxes, net of federal benefit
|
0.2 | 0.5 | 1.3 | |||||||
Difference
between US and foreign rates
|
1.8 | 1.6 | 2.2 | |||||||
Nondeductible
goodwill
|
- | - | 3.1 | |||||||
Other,
net
|
0.4 | (0.7 | ) | 0.7 | ||||||
Effective
rate
|
34.5 | 31.0 | 38.1 |
December
31,
|
||||||||
2008
|
2007
|
|||||||
(in
millions)
|
||||||||
Deferred
tax assets
|
||||||||
Loss
carryforwards
|
$ | 36 | $ | 21 | ||||
Ecuador
investment
|
18 | - | ||||||
Accrued
expenses
|
32 | 26 | ||||||
Allowance
for doubtful accounts
|
20 | 4 | ||||||
Fair
value of derivative instruments
|
- | 177 | ||||||
AOCL
- pension asset/obligation
|
20 | - | ||||||
Postretirement
benefits
|
31 | 10 | ||||||
Deferred
compensation
|
63 | 61 | ||||||
Foreign
tax credits
|
51 | 82 | ||||||
Other
|
27 | 14 | ||||||
Total
deferred tax assets
|
298 | 395 | ||||||
Valuation
allowance - foreign loss carryforwards
|
(35 | ) | (18 | ) | ||||
Valuation
allowance - foreign tax credits
|
(51 | ) | (57 | ) | ||||
Valuation
allowance - Ecuador
investment
|
(18 | ) | - | |||||
Net
deferred tax assets
|
194 | 320 | ||||||
Deferred
tax liabilities
|
||||||||
Property, plant and
equipment, principally due to differences
in depreciation, amortization, lease impairment and
abandonments
|
(2,388 | ) | (2,184 | ) | ||||
Commodity
derivative assets
|
(122 | ) | - | |||||
Other
|
- | 11 | ||||||
Total
deferred tax liability
|
(2,510 | ) | (2,173 | ) | ||||
Net
deferred tax liability
|
$ | (2,316 | ) | $ | (1,853 | ) |
December
31,
|
||||||||
2008
|
2007
|
|||||||
(in
millions)
|
||||||||
Deferred
income tax asset
|
$ | - | $ | 131 | ||||
Deferred
income tax liability - current
|
(142 | ) | - | |||||
Deferred
income tax liability - noncurrent
|
(2,174 | ) | (1,984 | ) | ||||
Net
deferred tax liability
|
$ | (2,316 | ) | $ | (1,853 | ) |
Earliest
Year
|
|
Remaining
Open
|
|
Tax
Jurisdiction
|
to
Examination
|
United
States
|
2005
|
Equatorial
Guinea
|
2006
|
China
|
2006
|
Israel
|
2000
|
UK
|
2006
|
the
Netherlands
|
2005
|
Year
Ended
|
||||||||
December
31,
|
||||||||
2008
|
2007
|
|||||||
(in
millions)
|
||||||||
Asset
retirement obligations, beginning of year
|
$ | 144 | $ |
196
|
||||
Liabilities
incurred in current period
|
15 |
9
|
||||||
Liabilities
settled in current period
|
(33 | ) |
(177
|
) | ||||
Revisions
|
75 |
108
|
||||||
Accretion
expense
|
10 |
8
|
||||||
Asset
retirement obligations, end of year
|
$ | 211 | $ |
144
|
||||
Current
portion
|
$ | 27 | $ |
13
|
||||
Noncurrent
portion
|
184 |
131
|
Note
11—Equity Method
Investments
|
|
·
|
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,
|
|||||||
2008
|
2007
|
||||||
(in
millions)
|
|||||||
Equity
method investments
|
|||||||
AMPCO
|
$ | 190 | $ | 200 | |||
Alba
Plant
|
106 | 142 | |||||
Other
|
15 | 15 | |||||
Total
equity method investments
|
$ | 311 | 357 |
December
31,
|
||||||||||
2008
|
2007
|
|||||||||
(in
millions)
|
||||||||||
Balance
sheet information
|
||||||||||
Current
assets
|
$ | 283 | $ | 408 | ||||||
Noncurrent
assets
|
783 | 814 | ||||||||
Current
liabilities
|
248 | 273 | ||||||||
Noncurrent
liabilities
|
43 | 31 | ||||||||
Year
Ended December 31,
|
||||||||||
2008
|
2007
|
2006
|
||||||||
(in
millions)
|
||||||||||
Statements
of operations information
|
||||||||||
Operating
revenues
|
$ | 1,022 | $ | 934 | $ | 702 | ||||
Less
cost of goods sold
|
250 | 220 | 202 | |||||||
Gross
margin
|
772 | 714 | 500 | |||||||
Less
other expense
|
37 | 36 | 48 | |||||||
Less income tax expense
(1)
|
183 | 44 | 23 | |||||||
Net
income
|
$ | 552 | $ | 634 | $ | 429 |
(1)
|
The
increase in income tax expense in 2008 is due to the expiration of the
Alba Plant tax holiday.
|
Retirement
and
|
Medical
and
|
|||||||||||||||
Restoration
Plans
|
Life
Plans
|
|||||||||||||||
2008
|
2007
|
2008
|
2007
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Change
in benefit obligation
|
||||||||||||||||
Benefit
obligation at beginning of year
|
$ | 188 | $ | 175 | $ | 22 | $ | 22 | ||||||||
Service
cost
|
12 | 12 | 2 | 2 | ||||||||||||
Interest
cost
|
12 | 10 | 1 | 1 | ||||||||||||
Amendments
|
- | 8 | - | - | ||||||||||||
Benefits
paid
|
(17 | ) | (6 | ) | (1 | ) | (1 | ) | ||||||||
Actuarial
(gain) loss
|
(1 | ) | (11 | ) | (2 | ) | (2 | ) | ||||||||
Benefit
obligation at end of year
|
194 | 188 | 22 | 22 | ||||||||||||
Change
in plan assets
|
||||||||||||||||
Fair
value of plan assets at beginning of year
|
155 | 137 | - | - | ||||||||||||
Actual
return on plan assets
|
(43 | ) | 13 | - | - | |||||||||||
Employer
contributions
|
37 | 11 | 1 | 1 | ||||||||||||
Benefits
paid
|
(17 | ) | (6 | ) | (1 | ) | (1 | ) | ||||||||
Fair
value of plan assets at end of year
|
132 | 155 | - | - | ||||||||||||
Funded
status
|
||||||||||||||||
Funded
status at end of year
|
(62 | ) | (33 | ) | (22 | ) | (22 | ) | ||||||||
Net amount
recognized in consolidated balance sheets (after adoption of FAS
158)
|
(62 | ) | (33 | ) | (22 | ) | (22 | ) | ||||||||
Amounts
recognized in consolidated balance sheets consist of:
|
||||||||||||||||
Current
liabilities
|
(2 | ) | (3 | ) | (1 | ) | (1 | ) | ||||||||
Noncurrent
liabilities
|
(60 | ) | (30 | ) | (21 | ) | (21 | ) | ||||||||
Net amount
recognized in consolidated balance sheets (after adoption of FAS
158)
|
(62 | ) | (33 | ) | (22 | ) | (22 | ) | ||||||||
Amounts
not yet reflected in net periodic benefit cost and included in
AOCL
|
||||||||||||||||
Transition
obligation
|
- | (1 | ) | - | - | |||||||||||
Prior
service (cost) credit
|
(3 | ) | (3 | ) | 5 | 6 | ||||||||||
Accumulated
loss
|
(86 | ) | (34 | ) | (10 | ) | (14 | ) | ||||||||
AOCL
|
(89 | ) | (38 | ) | (5 | ) | (8 | ) | ||||||||
Cumulative
employer contributions in excess of net periodic benefit
cost
|
27 | 5 | (17 | ) | (14 | ) | ||||||||||
Net
amount recognized in consolidated balance sheet (after adoption of FAS
158)
|
$ | (62 | ) | (33 | ) | $ | (22 | ) | (22 | ) |
Retirement
and
|
Medical
and
|
|||||||||||||||||||||||
Restoration
Plans
|
Life
Plans
|
|||||||||||||||||||||||
Year
Ended December 31,
|
Year
Ended December 31,
|
|||||||||||||||||||||||
2008
|
2007
|
2006
|
2008
|
2007
|
2006
|
|||||||||||||||||||
(in
millions)
|
||||||||||||||||||||||||
Components
of net periodic benefit cost
|
||||||||||||||||||||||||
Service
cost
|
$ | 12 | $ | 12 | $ | 12 | $ | 2 | $ | 2 | $ | 2 | ||||||||||||
Interest
cost
|
12 | 10 | 9 | 1 | 1 | 1 | ||||||||||||||||||
Expected
return on plan assets
|
(12 | ) | (11 | ) | (9 | ) | - | - | - | |||||||||||||||
Amortization
of prior service (credit) cost
|
- | - | - | (1 | ) | (1 | ) | - | ||||||||||||||||
Amortization
of net loss
|
2 | 3 | 3 | 1 | 1 | 1 | ||||||||||||||||||
Net
periodic benefit cost
|
$ | 14 | $ | 14 | $ | 15 | $ | 3 | $ | 3 | $ | 4 | ||||||||||||
Other
changes recognized in AOCL
|
||||||||||||||||||||||||
Prior
service cost arising during period
|
$ | - | $ | 8 | * | $ | - | $ | - | * | ||||||||||||||
Net
loss (gain) arising during period
|
53 | (13 | ) | * | (3 | ) | (3 | ) | * | |||||||||||||||
Amortization
of prior service credit
|
- | - | * | 1 | 1 | * | ||||||||||||||||||
Amortization
of net loss
|
(2 | ) | (3 | ) | * | (1 | ) | (1 | ) | * | ||||||||||||||
Total
recognized in AOCL
|
$ | 51 | $ | (8 | ) | * | $ | (3 | ) | $ | (3 | ) | * | |||||||||||
Expected
amortizations for next fiscal year
|
||||||||||||||||||||||||
Amortization
of prior service cost (credit)
|
$ | - | $ | - | $ | (1 | ) | $ | (1 | ) | $ | (1 | ) | $ | (1 | ) | ||||||||
Amortization
of net loss
|
2 | 2 | 3 | 1 | 1 | 1 | ||||||||||||||||||
Weighted-average
assumptions used to determine benefit obligations
|
||||||||||||||||||||||||
Discount
rate (1)
|
6.00% / 6.25 | % | 6.50 | % | 5.75 | % | 6.25 | % | 6.25 | % | 5.75 | % | ||||||||||||
Rate
of compensation increase
|
5.00 | % | 5.00 | % | 5.00 | % | - | - | - | |||||||||||||||
Weighted-average
assumptions used to determine net periodic benefit costs
|
||||||||||||||||||||||||
Discount rate
(2)
|
6.50 | % | 5.75 | % | 5.50% / 6.25 | % | 6.25 | % | 5.75 | % | 5.50% / 6.25 | % | ||||||||||||
Expected
long-term rate of return on plan assets
|
8.25 | % | 8.25 | % | 8.25 | % | - | - | - | |||||||||||||||
Rate
of compensation increase
|
5.00 | % | 5.00 | % | 5.00 | % | - | - | - |
*
|
Not
applicable due to change in method of accounting for defined benefit and
other post retirement plans.
|
(1)
|
The
discount rate was 6.00% for the retirement plan and 6.25% for the
restoration plan at December 31,
2008.
|
(2)
|
The
net periodic benefit cost was remeasured at May 1, 2006 using a
discount rate of 6.25%, due to changes in plan
provisions.
|
Retirement
and
|
|||||||
Restoration
Plans
|
|||||||
2008
|
2007
|
||||||
(in millions) | |||||||
Accumulated
benefit obligation
|
$ | 169 | $ | 163 | |||
Information for
pension plans with projected benefit obligations in excess of plan
assets
|
|||||||
Projected
benefit obligation
|
194 | 188 | |||||
Fair
value of plan assets
|
132 | 155 | |||||
Information
for pension plans with accumulated benefit obligations in excess of plan
assets
|
|||||||
Accumulated
benefit obligation
|
169 | 25 | |||||
Fair
value of plan assets
|
132 | - |
2008
|
2007
|
|||||
Health
care cost trend rate assumed for next year
|
8%
|
9%
|
||||
Rate
to which the cost trend rate is assumed to decline (ultimate trend
rate)
|
5%
|
5%
|
||||
Year
rate reaches ultimate trend rate
|
2012
|
2012
|
1%
Increase
|
1%
Decrease
|
|||||||
(in
millions)
|
||||||||
Effect
on total service and interest cost components for 2008
|
$ | - | $ | - | ||||
Effect
on year-end 2008 postretirement benefit obligation
|
2 | (2 | ) |
Target
|
||||||||||||
Allocation
|
Plan
Assets
|
|||||||||||
2009
|
2008
|
2007
|
||||||||||
Asset
Category
|
||||||||||||
Equity
securities
|
70%
|
65%
|
70%
|
|||||||||
Fixed
income
|
30%
|
35%
|
30%
|
|||||||||
Total
|
100%
|
100%
|
100%
|
Retirement
and
|
Medical
and
|
|||||||
Restoration
Plans
|
Life
Plans
|
|||||||
(in
millions)
|
||||||||
2009
|
$ | 18 | $ | 1 | ||||
2010
|
13 | 2 | ||||||
2011
|
16 | 2 | ||||||
2012
|
17 | 2 | ||||||
2013
|
16 | 2 | ||||||
Years
2014 to 2018
|
99 | 14 |
December
31,
|
||||||||
2008
|
2007
|
|||||||
(in
millions, except share amounts)
|
||||||||
Rabbi
trust assets
|
||||||||
Mutual
fund investments
|
$ | 71 | $ | 107 | ||||
Noble
Energy common stock (at market value) (1)
|
52 | 87 | ||||||
Total
rabbi trust assets
|
123 | 194 | ||||||
Liability
under Patina deferred compensation plan
|
$ | 123 | $ | 194 | ||||
Number
of shares of Noble Energy common stock held by rabbi trust
|
1,051,032 | 1,101,032 |
(1)
|
Shares
of Noble Energy common stock are accounted for as treasury stock and
recorded at cost in the consolidated balance
sheets.
|
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
(in
millions)
|
||||||||||||
Stock-based
compensation expense included in
|
||||||||||||
General
and administrative expense
|
$ | 38 | $ | 25 | $ | 11 | ||||||
Exploration
expense and other
|
1 | 2 | 1 | |||||||||
Total
stock-based compensation expense
|
$ | 39 | $ | 27 | $ | 12 | ||||||
Tax
benefit recognized
|
$ | (15 | ) | $ | (10 | ) | $ | (4 | ) |
1992 Stock Option and
Restricted Stock Plan
|
2004 Long-Term
Incentive Plan
|
1988 Nonqualified
Stock Option Plan for Non-Employee
Directors
|
Patina Stock Option
Plans
|
|
·
|
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.
|
The
assumptions used in valuing stock options were as
follows:
|
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
(weighted
averages)
|
||||||||||||
Expected
term (in years)
|
5.5 | 5.5 | 5.5 | |||||||||
Expected
volatility
|
27.7 | % | 29.6 | % | 31.8 | % | ||||||
Risk-free
rate
|
2.9 | % | 4.7 | % | 4.7 | % | ||||||
Expected
dividend yield
|
1.0 | % | 0.6 | % | 0.8 | % |
Weighted
|
||||||||||||||
Weighted
|
Average
|
|||||||||||||
Average
|
Remaining
|
Aggregate
|
||||||||||||
Exercise
|
Contractual
|
Intrinsic
|
||||||||||||
Options
|
Price
|
Term
|
Value
|
|||||||||||
(per
share)
|
(in
years)
|
(in
millions)
|
||||||||||||
Outstanding
at December 31, 2007
|
6,175,061 | $ | 32.98 | |||||||||||
Granted
|
1,139,758 | 73.14 | ||||||||||||
Exercised
|
(1,080,116 | ) | 24.31 | |||||||||||
Forfeited
|
(152,328 | ) | 61.22 | |||||||||||
Outstanding
at December 31, 2008
|
6,082,375 | $ | 41.41 |
5.6
|
$ |
80
|
||||||||
Exercisable
at December 31, 2008
|
3,927,682 | $ | 29.80 |
3.9
|
$ |
79
|
Shares
|
Weighted
|
Shares
|
Weighted
|
|||||||||||||
Subject
to
|
Average
|
Subject
to
|
Average
|
|||||||||||||
Service
|
Grant
Date
|
Market
|
Grant
Date
|
|||||||||||||
Conditions
|
Fair
Value
|
Conditions
|
Fair
Value
|
|||||||||||||
(per
share)
|
(per
share)
|
|||||||||||||||
Outstanding
at December 31, 2007
|
567,590 | $ | 52.33 | 124,137 | $ | 33.11 | ||||||||||
Granted
|
462,917 | 73.92 | - | - | ||||||||||||
Vested
|
(80,347 | ) | 52.46 | (54,199 | ) | 29.87 | ||||||||||
Forfeited
|
(59,133 | ) | 61.78 | (1,445 | ) | 45.94 | ||||||||||
Outstanding
at December 31, 2008
|
891,027 | $ | 62.91 | 68,493 | $ | 35.40 |
Year
Ended
|
||||
December
31,
|
||||
2006
|
||||
Number
of simulations
|
100,000 | |||
Expected
volatility
|
28.4 | % | ||
Risk-free
rate
|
4.4 | % |
Year
Ended December 31,
|
|||||||||||||||||||||||
2008
|
2007
|
2006
|
|||||||||||||||||||||
Income
|
Shares
|
Income
|
Shares
|
Income
|
Shares
|
||||||||||||||||||
(in
millions, except share and per share amounts)
|
|||||||||||||||||||||||
Net
income
|
$ | 1,350 | 173 | $ | 944 | 171 | $ | 678 | 176 | ||||||||||||||
Basic
Earnings per Share
|
$ | 7.83 | $ | 5.52 | $ | 3.86 | |||||||||||||||||
Net
income
|
$ | 1,350 | 173 | $ | 944 | 171 | $ | 678 | 176 | ||||||||||||||
Effect
of dilutive stock options and restricted stock awards
|
- | 2 | - | 2 | - | 3 | |||||||||||||||||
Effect
of shares of Noble Energy common stock held in rabbi
trust
|
(20 | ) | 1 | - | - | - | - | ||||||||||||||||
Net
income available to common shareholders
|
$ | 1,330 | 176 | $ | 944 | 173 | $ | 678 | 179 | ||||||||||||||
Diluted
Earnings per Share (1)
|
$ | 7.58 | $ | 5.45 | $ | 3.79 |
(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 Noble Energy shares held in a rabbi trust. When dilutive, the
deferred compensation gain or loss (net of tax) is excluded from net
income while the Noble Energy shares held in the rabbi trust are included
in the diluted share count.
|
Weighted
Outstanding Awards and Shares
|
Weighted
Average Exercise Price
|
|||||
(in
millions, except per share amounts)
|
||||||
Year
Ended December 31, 2008
|
||||||
Stock
options
|
1
|
$ |
67.64
|
|||
Total
excluded from diluted EPS calculation
|
1
|
|||||
Year
Ended December 31, 2007
|
||||||
Stock
options
|
1
|
$ |
52.41
|
|||
Noble
Energy common stock held in rabbi trust and shares of restricted
stock
|
1
|
|||||
Total
excluded from diluted EPS calculation
|
2
|
|||||
Year
Ended December 31, 2006
|
||||||
Stock
options
|
1
|
$ |
45.19
|
|||
Noble
Energy common stock held in rabbi trust and shares of restricted
stock
|
1
|
|||||
Total
excluded from diluted EPS calculation
|
2
|
Other
Int'l,
|
|||||||||||||||||||
United
|
West
|
North
|
Corporate
&
|
||||||||||||||||
Total
|
States
|
Africa
|
Sea
|
Israel
|
Marketing
|
||||||||||||||
(in
millions)
|
|||||||||||||||||||
Year
Ended December 31, 2008
|
|||||||||||||||||||
Revenues
from third parties
|
$ | 4,058 | $ | 2,315 | $ | 541 | $ | 410 | $ | 157 | $ | 635 | |||||||
Amount
reclassified from AOCL (1)
|
(331 | ) | (290 | ) | (41 | ) | - | - | - | ||||||||||
Intersegment
revenue
|
- | 434 | - | - | - | (434 | ) | ||||||||||||
Income
from equity method investees
|
174 | - | 174 | - | - | - | |||||||||||||
Total
Revenues
|
3,901 | 2,459 | 674 | 410 | 157 | 201 | |||||||||||||
DD&A
|
791 | 646 | 34 | 55 | 24 | 32 | |||||||||||||
Loss
on involuntary conversion of assets
|
9 | 9 | - | - | - | - | |||||||||||||
Impairment
of assets
|
294 | 224 | - | - | - | 70 | |||||||||||||
Gain
on derivative instruments
|
(440 | ) | (363 | ) | (77 | ) | - | - | - | ||||||||||
Income
(loss) before income taxes
|
2,061 | 1,333 | 689 | 284 | 122 | (367 | ) | ||||||||||||
Equity
method investments
|
311 | - | 311 | - | - | - | |||||||||||||
Additions
to long-lived assets
|
2,179 | 1,842 | 143 | 94 | 39 | 61 | |||||||||||||
Total
assets at December 31, 2008
(2)
|
12,384 | 9,212 | 1,614 | 775 | 366 | 417 | |||||||||||||
Year
Ended December 31, 2007
|
|||||||||||||||||||
Revenues
from third parties
|
$ | 3,115 | $ | 1,651 | $ | 418 | $ | 364 | $ | 113 | $ | 569 | |||||||
Amount
reclassified from AOCL (1)
|
(54 | ) | (42 | ) | (12 | ) | - | - | - | ||||||||||
Intersegment
revenue
|
- | 343 | - | - | - | (343 | ) | ||||||||||||
Income
from equity method investees
|
211 | - | 211 | - | - | - | |||||||||||||
Total
Revenues
|
3,272 | 1,952 | 617 | 364 | 113 | 226 | |||||||||||||
DD&A
|
736 | 580 | 25 | 81 | 18 | 32 | |||||||||||||
Loss
on involuntary conversion of assets
|
51 | 51 | - | - | - | - | |||||||||||||
Impairment
of assets
|
4 | 4 | - | - | - | - | |||||||||||||
Gain
on derivative instruments
|
(2 | ) | (2 | ) | - | - | - | - | |||||||||||
Income
(loss) before income taxes
|
1,368 | 810 | 517 | 221 | 86 | (266 | ) | ||||||||||||
Equity
method investments
|
357 | - | 357 | - | - | - | |||||||||||||
Additions
to long-lived assets
|
1,623 | 1,285 | 151 | 83 | 26 | 78 | |||||||||||||
Total
assets at December 31, 2007
(2)
|
10,831 | 7,918 | 1,355 | 562 | 268 | 728 | |||||||||||||
Year
Ended December 31, 2006
|
|||||||||||||||||||
Revenues
from third parties
|
$ | 3,033 | $ | 1,743 | $ | 414 | $ | 115 | $ | 92 | $ | 669 | |||||||
Amount
reclassified from AOCL (1)
|
(232 | ) | (232 | ) | - | - | - | - | |||||||||||
Intersegment
revenue
|
- | 426 | - | - | - | (426 | ) | ||||||||||||
Income
from equity method investees
|
139 | - | 139 | - | - | - | |||||||||||||
Total
Revenues
|
2,940 | 1,937 | 553 | 115 | 92 | 243 | |||||||||||||
DD&A
|
633 | 552 | 24 | 9 | 14 | 34 | |||||||||||||
Impairment
of assets
|
9 | 9 | - | - | - | - | |||||||||||||
Loss
on derivative instruments
|
392 | 392 | - | - | - | - | |||||||||||||
Income
(loss) before income taxes
|
1,096 | 631 | 494 | 73 | 71 | (173 | ) | ||||||||||||
Equity
method investments
|
373 | - | 373 | - | - | - | |||||||||||||
Additions
to long-lived assets
|
1,895 | 1,456 | 46 | 336 | 15 | 42 | |||||||||||||
Total
assets at December 31, 2006 (2)
|
9,589 | 7,225 | 961 | 343 | 257 | 803 |
(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)
|
The
US reporting unit includes goodwill of $759 million at December 31, 2008,
$761 million at December 31, 2007, and $781 million at December 31,
2006.
|
Year
Ended December 31,
|
||||||||
2008
|
2007
|
|||||||
Common
stock shares issued
|
||||||||
Shares,
beginning of period
|
190,814,309 | 188,808,087 | ||||||
Exercise
of common stock options
|
1,080,116 | 1,479,040 | ||||||
Restricted
stock awards, net of forfeitures
|
402,339 | 527,182 | ||||||
Shares,
end of period
|
192,296,764 | 190,814,309 | ||||||
Treasury
stock
|
||||||||
Shares,
beginning of period
|
18,580,865 | 16,574,384 | ||||||
Shares received from
employees in payment of withholding taxes due on vesting of shares
of restricted stock
|
32,544 | - | ||||||
Shares
purchased pursuant to share buyback program
|
- | 2,006,481 | ||||||
Shares,
end of period
|
18,613,409 | 18,580,865 |
Accumulated
Other Comprehensive Loss
|
||||||||||||
Oil
and Gas Cash Flow Hedges
|
Pension-Related
and Other
|
Total
|
||||||||||
(in
millions)
|
||||||||||||
December
31, 2005
|
$ | (764 | ) | $ | (20 | ) | $ | (784 | ) | |||
Cash
flow hedges
|
||||||||||||
Realized
amounts reclassified into earnings
|
145 | 1 | 146 | |||||||||
Unrealized
change in fair value
|
250 | - | 250 | |||||||||
Unrealized
amounts reclassified into earnings
|
265 | - | 265 | |||||||||
Net
change in minimum pension liability and other
|
- | 16 | 16 | |||||||||
Adoption
of SFAS 158
|
- | (33 | ) | (33 | ) | |||||||
December
31, 2006
|
(104 | ) | (36 | ) | (140 | ) | ||||||
Cash
flow hedges
|
||||||||||||
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 | ) |
Drilling,
Equipment, and Purchase Obligations
|
Throughput
Agreement
|
Transportation
and Gathering
|
Operating
Lease Obligations
|
Total
|
|||||||||||
(in
millions)
|
|||||||||||||||
2009
|
$ |
485
|
$ |
14
|
$ |
12
|
$ |
12
|
$ |
523
|
|||||
2010
|
439
|
19
|
9
|
10
|
477
|
|
|||||||||
2011
|
399
|
19
|
8
|
8
|
434
|
||||||||||
2012
|
72
|
19
|
5
|
7
|
103
|
||||||||||
2013
|
-
|
19
|
5
|
1
|
25
|
||||||||||
2014
and thereafter
|
-
|
5
|
4
|
18
|
27
|
||||||||||
Total
|
$ |
1,395
|
$ |
95
|
$ |
43
|
$ |
56
|
$ |
1,589
|
|
·
|
Commodity
Prices - Economic producibility of reserves and discounted cash flows will
be based on a 12-month average commodity price unless contractual
arrangements designate the price to be
used.
|
|
·
|
Disclosure
of Unproved Reserves - Probable and possible reserves may be disclosed
separately on a voluntary basis.
|
|
·
|
Proved
Undeveloped Reserve Guidelines – Reserves may be classified as proved
undeveloped if there is a high degree of confidence that the quantities
will be recovered.
|
|
·
|
Reserve
Estimation Using New Technologies - Reserves may be estimated through the
use of reliable technology in addition to flow tests and production
history.
|
|
·
|
Reserve
Personnel and Estimation Process - Additional disclosure is required
regarding the qualifications of the chief technical person who oversees
our reserves estimation process. We will also be required to
provide a general discussion of our internal controls used to assure the
objectivity of the reserves
estimate.
|
|
·
|
Disclosure
by Geographic Area - Reserves in foreign countries or continents must be
presented separately if they represent more than 15% of our total oil and
gas proved reserves.
|
|
·
|
Non-Traditional
Resources – The
definition of oil and gas producing activities will expand and focus on
the marketable product rather than the method of
extraction.
|
Crude
Oil, Condensate and NGLs (MMBbls)
|
||||||||||||||||||||
United
|
West
|
North
|
Other
|
|||||||||||||||||
States
|
Africa
|
Sea
|
Int'l (1)
|
Total
|
||||||||||||||||
Proved
reserves as of:
|
||||||||||||||||||||
December
31, 2005
|
152 | 101 | 20 | 18 | 291 | |||||||||||||||
Revisions
of previous estimates
|
- | (2 | ) | - | - | (2 | ) | |||||||||||||
Extensions,
discoveries and other additions (2)
|
23 | - | - | 2 | 25 | |||||||||||||||
Purchase
of minerals in place (3)
|
19 | - | - | - | 19 | |||||||||||||||
Sale
of minerals in place
(4)
|
(7 | ) | - | - | - | (7 | ) | |||||||||||||
Production
(5)
|
(17 | ) | (9 | ) | (1 | ) | (3 | ) | (30 | ) | ||||||||||
December
31, 2006
|
170 | 90 | 19 | 17 | 296 | |||||||||||||||
Revisions
of previous estimates (6)
|
28 | - | 1 | - | 29 | |||||||||||||||
Extensions,
discoveries and other additions (7)
|
27 | - | 10 | - | 37 | |||||||||||||||
Purchase
of minerals in place
|
- | - | - | - | - | |||||||||||||||
Sale
of minerals in place
|
(2 | ) | - | - | - | (2 | ) | |||||||||||||
Production
(5)
|
(16 | ) | (8 | ) | (5 | ) | (2 | ) | (31 | ) | ||||||||||
December
31, 2007
|
207 | 82 | 25 | 15 | 329 | |||||||||||||||
Revisions
of previous estimates (8)
|
(10 | ) | 1 | - | - | (9 | ) | |||||||||||||
Extensions,
discoveries and other additions (9)
|
16 | - | 2 | 9 | 27 | |||||||||||||||
Purchase
of minerals in place
|
3 | - | - | - | 3 | |||||||||||||||
Sale
of minerals in place
(10)
|
- | - | - | (7 | ) | (7 | ) | |||||||||||||
Production
(5)
|
(18 | ) | (8 | ) | (4 | ) | (2 | ) | (32 | ) | ||||||||||
December
31, 2008
|
198 | 75 | 23 | 15 | 311 | |||||||||||||||
Proved
developed reserves as of:
|
||||||||||||||||||||
December
31, 2005
|
114 | 101 | 8 | 16 | 239 | |||||||||||||||
December
31, 2006
|
115 | 90 | 19 | 16 | 240 | |||||||||||||||
December
31, 2007
|
129 | 71 | 15 | 14 | 229 | |||||||||||||||
December
31, 2008
|
121 | 57 | 15 | 6 | 199 |
(1)
|
Other
International includes China and Argentina. We sold our assets in
Argentina in 2008.
|
(2)
|
The
increase in US proved reserves includes 14 MMBbl in the US Wattenberg
field, primarily due to infill drilling
activities.
|
(3)
|
Purchase
of minerals in place includes 18 MMBbl acquired in the purchase of U.S.
Exploration. See Note 4—Acquisitions and
Divestitures.
|
(4)
|
Sale
of minerals in place is primarily due to the sale of Gulf of Mexico shelf
properties. See Note 4—Acquisitions and
Divestitures.
|
(5)
|
West
Africa production includes sales from the Alba field to the Alba LPG plant
of 3 MMBbl in 2008, 3 MMBbl in 2007, and 3 MMBbl in
2006.
|
(6)
|
The
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.
|
(7)
|
The
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.
|
(8)
|
The
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.
|
(9)
|
The
increase in proved reserves includes 13 MMBbl in the US Wattenberg field,
primarily due to infill drilling activities, and 9 MMBbl in
China.
|
(10)
|
Decrease
due to sale of our assets in Argentina. See Note 4 –
Acquisitions and Divestitures.
|
Proved Gas
Reserves (Unaudited)
|
Natural
Gas and Casinghead Gas (Bcf)
|
||||||||||||||||||||||||
United
|
West
|
Other
|
||||||||||||||||||||||
States
|
Africa
|
Israel
|
Ecuador
|
Int'l (1)
|
Total
|
|||||||||||||||||||
Proved
reserves as of:
|
||||||||||||||||||||||||
December
31, 2005
|
1,641 | 901 | 394 | 144 | 11 | 3,091 | ||||||||||||||||||
Revisions
of previous estimates (2)
|
(83 | ) | 58 | - | 33 | 11 | 19 | |||||||||||||||||
Extensions,
discoveries and other additions (3)
|
314 | - | - | - | - | 314 | ||||||||||||||||||
Purchase
of minerals in place (4)
|
141 | 3 | - | - | - | 144 | ||||||||||||||||||
Sale
of minerals in place (5)
|
(110 | ) | - | - | - | - | (110 | ) | ||||||||||||||||
Production
|
(164 | ) | (17 | ) | (34 | ) | (9 | ) | (3 | ) | (227 | ) | ||||||||||||
December
31, 2006
|
1,739 | 945 | 360 | 168 | 19 | 3,231 | ||||||||||||||||||
Revisions
of previous estimates (6)
|
(67 | ) | 44 | - | 29 | (1 | ) | 5 | ||||||||||||||||
Extensions,
discoveries and other additions (7)
|
316 | - | - | - | 3 | 319 | ||||||||||||||||||
Purchase
of minerals in place
|
3 | - | - | - | - | 3 | ||||||||||||||||||
Sale
of minerals in place
|
- | - | - | - | - | - | ||||||||||||||||||
Production
|
(151 | ) | (48 | ) | (41 | ) | (9 | ) | (2 | ) | (251 | ) | ||||||||||||
December
31, 2007
|
1,840 | 941 | 319 | 188 | 19 | 3,307 | ||||||||||||||||||
Revisions
of previous estimates (8)
|
(253 | ) | 34 | 1 | - | 8 | (210 | ) | ||||||||||||||||
Extensions,
discoveries and other additions (9)
|
345 | 78 | 4 | - | - | 427 | ||||||||||||||||||
Purchase
of minerals in place (10)
|
72 | - | - | - | - | 72 | ||||||||||||||||||
Sale
of minerals in place
|
- | - | - | - | - | - | ||||||||||||||||||
Production
|
(145 | ) | (75 | ) | (51 | ) | (8 | ) | (2 | ) | (281 | ) | ||||||||||||
December
31, 2008
|
1,859 | 978 | 273 | 180 | 25 | 3,315 | ||||||||||||||||||
Proved
developed reserves as of:
|
||||||||||||||||||||||||
December
31, 2005
|
1,279 | 431 | 337 | 144 | 11 | 2,202 | ||||||||||||||||||
December
31, 2006
|
1,255 | 360 | 303 | 168 | 19 | 2,105 | ||||||||||||||||||
December
31, 2007
|
1,259 | 830 | 263 | 188 | 16 | 2,556 | ||||||||||||||||||
December
31, 2008
|
1,268 | 700 | 216 | 180 | 21 | 2,385 |
|
(1)
|
Other
International includes the North Sea, China and Argentina. We sold our
assets in Argentina in 2008.
|
(2)
|
West
Africa’s positive revisions are primarily due to additional production
allowances related to LNG sales.
|
|
Positive
revisions in Ecuador are related to better than expected well
performance.
|
(3)
|
The
increase in US proved reserves includes 140 Bcf in the Wattenberg field,
77 Bcf in the Piceance basin and 55 Bcf in the Mid-continent area,
primarily due to infill drilling
activities.
|
(4)
|
Purchase
of minerals in place includes 128 Bcf acquired in the purchase of U.S.
Exploration. See Note 4—Acquisitions and
Divestitures.
|
(5)
|
Sale
of minerals in place is primarily due to sale of Gulf of Mexico shelf
properties. See Note 4—Acquisitions and
Divestitures.
|
(6)
|
The
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. West Africa’s positive
revisions are primarily due to additional production allowances related to
LNG sales. Positive revisions in Ecuador are related to better
than expected well performance.
|
(7)
|
The
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.
|
(8)
|
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 oil reserves table as NGLs. West Africa’s positive
revisions are primarily due to additional production allowances related to
LNG sales.
|
(9)
|
The
increase in US proved reserves includes 106 Bcf in the Wattenberg field
and 173 Bcf in the Rockies, primarily from 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.
|
(10)
|
Purchase
of minerals in place is primarily due to the Mid-continent
acquisition. See Note 4—Acquisitions and
Divestitures.
|
Results
of Operations for Oil and Gas Producing Activities
(Unaudited)
|
Aggregate
results of operations in connection with crude oil and natural gas
producing activities are as
follows:
|
United
|
West
|
North
|
Other
|
|||||||||||||||||||||||||
States
|
Africa
|
Israel
|
Ecuador
|
Sea
|
Int'l
(1)
|
Total
|
||||||||||||||||||||||
(in
millions)
|
||||||||||||||||||||||||||||
Year
Ended December 31, 2008
|
||||||||||||||||||||||||||||
Revenues
|
||||||||||||||||||||||||||||
Sales
(2)
|
$ | 2,459 | $ | 500 | $ | 157 | $ | - | $ | 410 | $ | 125 | $ | 3,651 | ||||||||||||||
Sales
to affiliated power plant
|
- | - | - | 30 | - | - | 30 | |||||||||||||||||||||
Total
Revenues
|
2,459 | 500 | 157 | 30 | 410 | 125 | 3,681 | |||||||||||||||||||||
Production
costs (3)
|
470 | 42 | 12 | 12 | 66 | 45 | 647 | |||||||||||||||||||||
Exploration
expense
|
111 | 9 | 4 | 1 | 18 | 39 | 182 | |||||||||||||||||||||
DD&A
|
653 | 34 | 23 | 9 | 55 | 11 | 785 | |||||||||||||||||||||
Impairment
of assets
|
224 | - | - | - | - | - | 224 | |||||||||||||||||||||
Income
before income taxes
|
1,001 | 415 | 118 | 8 | 271 | 30 | 1,843 | |||||||||||||||||||||
Income
tax expense
|
339 | 99 | 22 | 2 | 132 | 17 | 611 | |||||||||||||||||||||
Results
of operations (4)
|
$ | 662 | $ | 316 | $ | 96 | $ | 6 | $ | 139 | $ | 13 | $ | 1,232 | ||||||||||||||
Equity
investee results of operations (5)
|
$ | - | $ | 118 | $ | - | $ | - | $ | - | $ | - | $ | 118 | ||||||||||||||
Year
Ended December 31, 2007
|
||||||||||||||||||||||||||||
Revenues
|
||||||||||||||||||||||||||||
Sales
(2)
|
$ | 1,952 | $ | 406 | $ | 113 | $ | - | $ | 364 | $ | 131 | $ | 2,966 | ||||||||||||||
Sales
to affiliated power plant
|
- | - | - | 35 | - | - | 35 | |||||||||||||||||||||
Total
Revenues
|
1,952 | 406 | 113 | 35 | 364 | 131 | 3,001 | |||||||||||||||||||||
Production
costs (3)
|
390 | 42 | 10 | 6 | 52 | 49 | 549 | |||||||||||||||||||||
Exploration
expense
|
122 | 44 | 1 | - | 17 | 3 | 187 | |||||||||||||||||||||
DD&A
|
595 | 25 | 18 | 11 | 81 | 20 | 750 | |||||||||||||||||||||
Impairment
of assets
|
4 | - | - | - | - | - | 4 | |||||||||||||||||||||
Income
before income taxes
|
841 | 295 | 84 | 18 | 214 | 59 | 1,511 | |||||||||||||||||||||
Income
tax expense
|
191 | 84 | 14 | 4 | 114 | 10 | 417 | |||||||||||||||||||||
Results
of operations (4)
|
$ | 650 | $ | 211 | $ | 70 | $ | 14 | $ | 100 | $ | 49 | 1,094 | |||||||||||||||
Equity
investee results of operations (5)
|
$ | - | $ | 128 | $ | - | $ | - | $ | - | $ | - | $ | 128 | ||||||||||||||
Year
Ended December 31, 2006
|
||||||||||||||||||||||||||||
Revenues
|
||||||||||||||||||||||||||||
Sales
(2)
|
$ | 1,937 | $ | 414 | $ | 92 | $ | - | $ | 115 | $ | 143 | $ | 2,701 | ||||||||||||||
Sales
to affiliated power plant
|
- | - | - | 34 | - | - | 34 | |||||||||||||||||||||
Total
Revenues
|
1,937 | 414 | 92 | 34 | 115 | 143 | 2,735 | |||||||||||||||||||||
Production
costs (3)
|
420 | 32 | 9 | 6 | 22 | 42 | 531 | |||||||||||||||||||||
Exploration
expense
|
113 | 7 | - | - | 11 | 12 | 143 | |||||||||||||||||||||
DD&A
|
571 | 23 | 14 | 12 | 9 | 26 | 655 | |||||||||||||||||||||
Impairment
of assets
|
9 | - | - | - | - | - | 9 | |||||||||||||||||||||
Income
before income taxes
|
824 | 352 | 69 | 16 | 73 | 63 | 1,397 | |||||||||||||||||||||
Income
tax expense
|
313 | 125 | 20 | 4 | 42 | 23 | 527 | |||||||||||||||||||||
Results
of operations (4)
|
$ | 511 | $ | 227 | $ | 49 | $ | 12 | $ | 31 | $ | 40 | $ | 870 | ||||||||||||||
Equity
investee results of operations (5)
|
$ | - | $ | 101 | $ | - | $ | - | $ | - | $ | - | $ | 101 |
(1)
|
Other
International includes China, Argentina (through February 2008) and
Suriname.
|
(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 oil and gas
operations expense, production and ad valorem taxes, transportation costs,
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.
|
(5)
|
Equity
investee results of operations represents our share of the Alba Plant
equity investee results of operations from oil and gas producing
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
|
West
|
North
|
Other
|
|||||||||||||||||||||||||
States
|
Africa
|
Israel
|
Ecuador
|
Sea
|
Int'l (2)
|
Total
|
||||||||||||||||||||||
(in
millions)
|
||||||||||||||||||||||||||||
Year
Ended December 31, 2008
|
||||||||||||||||||||||||||||
Property
acquisition costs
|
||||||||||||||||||||||||||||
Proved
(3)
|
$ | 256 | $ | - | $ | - | $ | - | $ | - | $ | - | $ | 256 | ||||||||||||||
Unproved
(4)
|
296 | - | - | - | 1 | 5 | 302 | |||||||||||||||||||||
Total
acquisition costs
|
552 | - | - | - | 1 | 5 | 558 | |||||||||||||||||||||
Exploration
costs
|
322 | 110 | 28 | 1 | 17 | 39 | 517 | |||||||||||||||||||||
Development costs (5) (6)
(7)
|
1,106 | 41 | 13 | 1 | 94 | 10 | 1,265 | |||||||||||||||||||||
Total
consolidated operations
|
$ | 1,980 | $ | 151 | $ | 41 | $ | 2 | $ | 112 | $ | 54 | $ | 2,340 | ||||||||||||||
Our
share of Alba Plant development costs
|
$ | - | $ | 2 | $ | - | $ | - | $ | - | $ | - | $ | 2 | ||||||||||||||
Year
Ended December 31, 2007
|
||||||||||||||||||||||||||||
Property
acquisition costs
|
||||||||||||||||||||||||||||
Proved
|
$ | 11 | $ | - | $ | - | $ | - | $ | - | $ | - | $ | 11 | ||||||||||||||
Unproved
|
145 | - | - | - | - | 1 | 146 | |||||||||||||||||||||
Total
acquisition costs
|
156 | - | - | - | - | 1 | 157 | |||||||||||||||||||||
Exploration
costs
|
184 | 179 | 2 | - | 52 | 3 | 420 | |||||||||||||||||||||
Development costs (5) (6)
(7)
|
1,081 | 15 | 25 | - | 47 | 23 | 1,191 | |||||||||||||||||||||
Total
consolidated operations
|
$ | 1,421 | $ | 194 | $ | 27 | $ | - | $ | 99 | $ | 27 | $ | 1,768 | ||||||||||||||
Our
share of Alba Plant development costs
|
$ | - | $ | 1 | $ | - | $ | - | $ | - | $ | - | $ | 1 | ||||||||||||||
Year
Ended December 31, 2006
|
||||||||||||||||||||||||||||
Property
acquisition costs
|
||||||||||||||||||||||||||||
Proved (8)
|
$ | 514 | $ | 8 | $ | - | $ | - | $ | - | $ | - | $ | 522 | ||||||||||||||
Unproved (8)
|
157 | 26 | 1 | - | 1 | - | 185 | |||||||||||||||||||||
Total
acquisition costs
|
671 | 34 | 1 | - | 1 | - | 707 | |||||||||||||||||||||
Exploration
costs
|
205 | 13 | - | - | 18 | 11 | 247 | |||||||||||||||||||||
Development costs (5) (6)
(7)
|
785 | 7 | 14 | - | 231 | 22 | 1,059 | |||||||||||||||||||||
Total
consolidated operations
|
$ | 1,661 | $ | 54 | $ | 15 | $ | - | $ | 250 | $ | 33 | $ | 2,013 | ||||||||||||||
Our
share of Alba Plant development costs
|
$ | - | $ | 1 | $ | - | $ | - | $ | - | $ | - | $ | 1 |
(1)
|
Costs
incurred include capitalized and expensed
items.
|
(2)
|
Other
International includes China, Argentina (through February 2008), Suriname
and other new ventures.
|
(3)
|
Includes
$254 million related to the Mid-continent
acquisition.
|
(4)
|
Includes
$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)
|
US
development costs include increases in asset retirement obligations of $34
million in 2008, $24 million in 2007, and $4 million in 2006. US
asset retirement costs of $33 million in 2006 were incurred as a
result of hurricane damage and are excluded from the costs incurred
schedule above as we recovered the costs from insurance
proceeds.
|
(6)
|
Worldwide
development costs include amounts spent to develop proved undeveloped
reserves of $1.0 billion in both 2008 and 2007, and $768 million in
2006. Worldwide development costs also include $191 million spent on
an FSPO in the North Sea Dumbarton field in
2006.
|
(7)
|
North
Sea development costs include increases in asset retirement obligations of
$18 million in 2008 and $4 million in
2007.
|
(8)
|
Includes
amounts allocated from the U.S. Exploration acquisition (2006) See Note 4—Acquisitions and
Divestitures.
|
December
31,
|
||||||||
2008
|
2007
|
|||||||
(in
millions)
|
||||||||
Unproved
oil and gas properties (1)
|
$ | 961 | $ | 1,165 | ||||
Proved
oil and gas properties
(2)
|
10,905 | 8,903 | ||||||
Total
oil and gas properties
|
11,866 | 10,068 | ||||||
Accumulated
DD&A
|
(3,022 | ) | (2,281 | ) | ||||
Net
capitalized costs
|
$ | 8,844 | $ | 7,787 | ||||
Our
share of Alba Plant net capitalized costs
|
$ | 113 | $ | 117 |
(1)
|
Unproved
oil and gas properties includes $465 million and $628 million at December
31, 2008 and 2007, 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 $180 million and
$91 million at December 31, 2008 and 2007,
respectively.
|
United
|
West
|
North
|
Other
|
|||||||||||||||||||||||||
States
|
Africa
|
Israel
|
Ecuador
|
Sea
|
Int'l (1)
|
Total
|
||||||||||||||||||||||
(in
millions)
|
||||||||||||||||||||||||||||
December
31, 2008
|
||||||||||||||||||||||||||||
Future
cash inflows (2)
|
$ | 16,551 | $ | 3,277 | $ | 938 | $ | 674 | $ | 1,170 | $ | 455 | $ | 23,065 | ||||||||||||||
Future
production costs (3)
|
4,646 | 784 | 120 | 249 | 442 | 185 | 6,426 | |||||||||||||||||||||
Future
development costs
|
3,082 | 62 | 160 | 17 | 184 | 148 | 3,653 | |||||||||||||||||||||
Future
income tax expense
|
2,594 | 774 | 173 | 119 | 305 | 49 | 4,014 | |||||||||||||||||||||
Future
net cash flows
|
6,229 | 1,657 | 485 | 289 | 239 | 73 | 8,972 | |||||||||||||||||||||
10%
annual discount for estimated timing of cash flows
|
3,180 | 608 | 106 | 157 | 14 | 43 | 4,108 | |||||||||||||||||||||
Standardized
measure of discounted future net cash flows
|
$ | 3,049 | $ | 1,049 | $ | 379 | $ | 132 | $ | 225 | $ | 30 | $ | 4,864 | ||||||||||||||
December
31, 2007
|
||||||||||||||||||||||||||||
Future
cash inflows (2)
|
$ | 30,733 | $ | 6,935 | $ | 858 | $ | 704 | $ | 2,492 | $ | 879 | $ | 42,601 | ||||||||||||||
Future
production costs (3)
|
5,936 | 1,112 | 180 | 174 | 516 | 335 | 8,253 | |||||||||||||||||||||
Future
development costs
|
3,136 | 202 | 88 | 12 | 200 | 15 | 3,653 | |||||||||||||||||||||
Future
income tax expense
|
6,622 | 1,348 | 146 | 115 | 881 | 125 | 9,237 | |||||||||||||||||||||
Future
net cash flows
|
15,039 | 4,273 | 444 | 403 | 895 | 404 | 21,458 | |||||||||||||||||||||
10%
annual discount for estimated timing of cash flows
|
7,398 | 1,705 | 163 | 227 | 221 | 93 | 9,807 | |||||||||||||||||||||
Standardized
measure of discounted future net cash flows
|
$ | 7,641 | $ | 2,568 | $ | 281 | $ | 176 | $ | 674 | $ | 311 | $ | 11,651 | ||||||||||||||
December
31, 2006
|
||||||||||||||||||||||||||||
Future
cash inflows (2)
|
$ | 18,948 | $ | 4,904 | $ | 972 | $ | 629 | $ | 1,225 | $ | 808 | $ | 27,486 | ||||||||||||||
Future
production costs (3)
|
4,551 | 738 | 146 | 162 | 327 | 187 | 6,111 | |||||||||||||||||||||
Future
development costs
|
2,846 | 80 | 90 | 12 | 35 | 28 | 3,091 | |||||||||||||||||||||
Future
income tax expense
|
3,422 | 1,348 | 187 | 130 | 435 | 177 | 5,699 | |||||||||||||||||||||
Future
net cash flows
|
8,129 | 2,738 | 549 | 325 | 428 | 416 | 12,585 | |||||||||||||||||||||
10%
annual discount for estimated timing of cash flows
|
3,966 | 1,132 | 215 | 170 | 95 | 120 | 5,698 | |||||||||||||||||||||
Standardized
measure of discounted future net cash flows
|
$ | 4,163 | $ | 1,606 | $ | 334 | $ | 155 | $ | 333 | $ | 296 | $ | 6,887 |
(1)
|
Other
International includes China and Argentina. We sold our assets in
Argentina in 2008.
|
(2)
|
The
standardized measure of discounted future net cash flows for 2008, 2007
and 2006 does not include cash flows relating to anticipated future
methanol or electricity sales.
|
(3)
|
Production
costs include oil and gas operations expense, production and ad valorem
taxes, transportation costs and general and administrative expense
supporting oil and gas operations.
|
Prices
and Other Assumptions in Discounted Future Net Cash Flows
(Unaudited)
|
United
|
West
|
North
|
Other
|
|||||||||||||||||||||||||
States
|
Africa
|
Israel
|
Ecuador
|
Sea
|
Int'l (1)
|
Total
|
||||||||||||||||||||||
December
31, 2008
|
||||||||||||||||||||||||||||
Average
crude oil price per Bbl
|
$ | 36.62 | $ | 40.51 | $ | - | $ | - | $ | 45.17 | $ | 31.69 | $ | 37.97 | ||||||||||||||
Average
natural gas price per Mcf
|
4.99 | 0.25 | 3.43 | 3.74 | 5.72 | - | 3.39 | |||||||||||||||||||||
December
31, 2007
|
||||||||||||||||||||||||||||
Average
crude oil price per Bbl
|
$ | 88.00 | $ | 81.26 | $ | - | $ | - | $ | 93.79 | $ | 61.72 | $ | 85.62 | ||||||||||||||
Average
natural gas price per Mcf
|
6.78 | 0.27 | 2.69 | 3.74 | 7.07 | - | 4.36 | |||||||||||||||||||||
December
31, 2006
|
||||||||||||||||||||||||||||
Average
crude oil price per Bbl
|
$ | 57.02 | $ | 51.49 | $ | - | $ | - | $ | 57.81 | $ | 48.04 | $ | 54.87 | ||||||||||||||
Average
natural gas price per Mcf
|
5.32 | 0.27 | 2.70 | 3.75 | 7.11 | 0.85 | 3.48 |
(1)
|
Other
International includes China at December 31, 2008, 2007 and 2006 and
Argentina at December 31, 2007 and
2006.
|
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
(in
millions)
|
||||||||||||
Imbalance
receivables
|
$ | 7 | $ | 13 | $ | 18 | ||||||
Imbalance
liabilities
|
8 | 10 | 17 |
Sources
of Changes in Discounted Future Net Cash Flows
(Unaudited)
|
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
(in
millions)
|
||||||||||||
Standardized
measure of discounted future net cash flows, beginning of
year
|
$ | 11,651 | $ | 6,887 | $ | 8,771 | ||||||
Changes
in standardized measure of dicounted future net cash
flows:
|
||||||||||||
Sales
of oil and gas produced, net of production costs
|
(3,030 | ) | (2,427 | ) | (2,177 | ) | ||||||
Net
changes in prices and production costs
|
(8,017 | ) | 5,266 | (2,788 | ) | |||||||
Extensions,
discoveries and improved recovery, less related costs
|
400 | 1,635 | 769 | |||||||||
Changes
in estimated future development costs
|
(883 | ) | (775 | ) | (558 | ) | ||||||
Development
costs incurred during the period
|
1,291 | 1,189 | 1,076 | |||||||||
Revisions
of previous quantity estimates
|
(617 | ) | 1,276 | (92 | ) | |||||||
Purchases
of minerals in place
|
182 | 6 | 573 | |||||||||
Sales
of minerals in place
|
(66 | ) | (95 | ) | (579 | ) | ||||||
Accretion
of discount
|
1,663 | 1,006 | 1,274 | |||||||||
Net
change in income taxes
|
2,853 | (1,900 | ) | 777 | ||||||||
Change
in timing of estimated future production and other
|
(563 | ) | (417 | ) | (159 | ) | ||||||
Aggregate
change in standardized measure of discounted future net cash
flows
|
(6,787 | ) | 4,764 | (1,884 | ) | |||||||
Standardized
measure of discounted future net cash flows, end of year
|
$ | 4,864 | $ | 11,651 | $ | 6,887 |
Quarter
Ended
|
|||||||||||||||||||
March
31,
|
June
30,
|
September
30,
|
December
31,
|
Total
|
|||||||||||||||
(in
millions except per share amounts)
|
|||||||||||||||||||
2008
(1)
|
|||||||||||||||||||
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
(4)
|
$ |
1.25
|
$
|
(0.84)
|
$ |
5.64
|
$ |
1.77
|
$ |
7.83
|
|||||||||
Diluted
(2)
(4)
|
1.20
|
(0.84)
|
5.37
|
1.72
|
7.58
|
||||||||||||||
2007
(3)
|
|||||||||||||||||||
Revenues
|
$ |
743
|
$ |
794
|
$ |
814
|
$ |
921
|
$ |
3,272
|
|||||||||
Income
before income taxes
|
304
|
293
|
344
|
427
|
1,368
|
||||||||||||||
Net
income
|
212
|
209
|
223
|
300
|
944
|
||||||||||||||
Earnings
per share:
|
|||||||||||||||||||
Basic
(4)
|
$
|
1.24
|
$ |
1.22
|
$ |
1.30
|
$ |
1.75
|
$
|
5.52
|
|||||||||
Diluted
(4)
|
1.22
|
1.21
|
1.28
|
1.73
|
5.45
|
(1)
|
First
quarter 2008 includes the
following:
|
|
·
|
$237
million loss on commodity derivative instruments. (See
Note 6–Derivative Instruments and Hedging
Activities).
|
|
Second
quarter 2008 includes the
following:
|
|
·
|
$828
million loss on commodity derivative instruments. (See
Note 6–Derivative Instruments and Hedging
Activities).
|
|
Third
quarter 2008 includes 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);
|
|
·
|
$38
million impairment of assets (See Note 4–Acquisitions
and Divestitures); and
|
|
·
|
$9
million loss on involuntary conversion (See Note
4–Acquisitions and
Divestitures).
|
|
Fourth
quarter 2008 includes the
following:
|
|
·
|
$630
million gain on commodity derivative instruments (See
Note 6–Derivative Instruments and Hedging Activities);
and
|
|
·
|
$256
million impairment of assets (See Note 3–Asset
Impairments).
|
(2)
|
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.
|
(3)
|
First
quarter 2007 includes the
following:
|
|
·
|
$13
million loss on involuntary conversion (See Note
4—Acquisitions and
Divestitures).
|
|
Second
quarter 2007 includes the
following:
|
|
·
|
$38
million loss on involuntary conversion (See Note
4—Acquisitions and
Divestitures).
|
(4)
|
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.
|
(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 19, 2009
|
By:
/s/ Charles D. Davidson
|
Charles
D. Davidson,
|
|
Chairman
of the Board, President,
|
|
Chief
Executive Officer and Director
|
|
Date:
February 19, 2009
|
By:
/s/ Chris Tong
|
Chris
Tong,
|
|
Senior
Vice President, Chief Financial Officer
|
|
Date:
February 19, 2009
|
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, President,
|
February 19,
2009
|
||||||||
Charles
D. Davidson
|
Chief
Executive Officer and Director
|
|||||||||
(Principal
Executive Officer)
|
||||||||||
/s/
Chris Tong
|
Senior
Vice President,
|
February 19,
2009
|
||||||||
Chris
Tong
|
Chief
Financial Officer
|
|||||||||
(Principal
Financial Officer)
|
||||||||||
/s/
Frederick B. Bruning
|
Vice
President, Chief Accounting Officer
|
February 19,
2009
|
||||||||
Frederick
B. Bruning
|
(Principal
Accounting Officer)
|
|||||||||
/s/
Jeffrey L. Berenson
|
Director
|
February 19,
2009
|
||||||||
Jeffrey
L. Berenson
|
|
|||||||||
/s/
Michael A. Cawley
|
Director
|
February 19,
2009
|
||||||||
Michael
A. Cawley
|
|
|||||||||
/s/
Edward F. Cox
|
Director
|
February 19,
2009
|
||||||||
Edward
F. Cox
|
|
|||||||||
/s/
Thomas J. Edelman
|
Director
|
February 19,
2009
|
||||||||
Thomas
J. Edelman
|
||||||||||
/s/
Eric P. Grubman
|
Director
|
February 19,
2009
|
||||||||
Eric
P. Grubman
|
||||||||||
s/
Kirby L. Hedrick
|
Director
|
February 19,
2009
|
||||||||
Kirby
L. Hedrick
|
||||||||||
/s/
Scott D. Urban
|
Director
|
February 19,
2009
|
||||||||
Scott
D. Urban
|
||||||||||
/s/
William T. Van Kleef
|
Director
|
February 19,
2009
|
||||||||
William
T. Van Kleef
|
Exhibit
Number
|
Exhibit**
|
|||
3.1
|
—
|
Certificate
of Incorporation, as amended through May 16, 2005, of the Registrant,
filed herewith.
|
||
3.2
|
—
|
By-Laws of Noble
Energy, Inc. as amended through December 9, 2008 (filed as
Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date
of Event: December 9, 2008) filed December 15, 2008 and incorporated
herein by reference).
|
||
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 October 14, 1993 between the Registrant and U.S.
Trust Company of Texas, N.A., as Trustee, relating to the Registrant’s 7
1/4% Notes Due 2023, including form of the Registrant’s 7 1/4% 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).
|
||
4.4
|
—
|
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).
|
||
4.5
|
—
|
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).
|
||
4.6
|
—
|
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 7 1/4%
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).
|
||
4.7
|
—
|
Third
Indenture Supplement relating to $200 million of the Registrant’s
5.25% 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 herewith.
|
||
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 herewith.
|
||
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
|
—
|
Guaranty
of the Registrant dated October 28, 1982, guaranteeing certain
obligations of Samedan (filed as Exhibit 10.12 to the Registrant’s
Annual Report on Form 10-K for the year ended
December 31, 1993 and incorporated herein by
reference).
|
||
10.8*
|
—
|
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).
|
||
10.9
|
—
|
364-day
Credit Agreement dated as of November 27, 2002 among the
Registrant, as borrower, JPMorgan Chase Bank, as the administrative agent
for the lenders, Wachovia Bank, National Association, as the syndication
agent for the lenders, Societe Generale, Citibank, N.A., Deutsche Bank Ag
New York Branch, and The Royal Bank of Scotland PLC, as co-documentation
agents, and certain commercial lending institutions, as lenders, (filed as
Exhibit 10.19 to the Registrant’s Annual Report on Form 10-K for
the year ended December 31, 2002 and incorporated herein by
reference).
|
Exhibit
Number
|
Exhibit**
|
|||
10.10
|
—
|
364-day
Credit Agreement dated as of October 30, 2003 among the
Registrant, as borrower, JPMorgan Chase Bank, as the administrative agent
for the lenders, Wachovia Bank, National Association, as the syndication
agent for the lenders, Societe Generale, Deutsche Bank Ag New York Branch,
and The Royal Bank of Scotland PLC, as co-documentation agents, and
certain commercial lending institutions, as lenders (filed as
Exhibit 10.20 to the Registrant’s Annual Report on Form 10-K for
the year ended December 31, 2003 and incorporated herein by
reference).
|
||
10.11
|
—
|
Term
Loan Agreement dated as of January 30, 2004 among Noble Energy
Mediterranean Ltd., as borrower, Sumitomo Mitsui Banking Corporation, as
initial lender and agent for the lenders, and certain commercial lending
institutions, as lenders (filed as Exhibit 99.1 to the Registrant’s
Current Report on Form 8-K (Date of Event:
January 30, 2004) filed May 10, 2004 and incorporated
herein by reference).
|
||
10.12
|
—
|
Guaranty
of the Company dated January 30, 2004 guaranteeing obligations
of Noble Energy Mediterranean, Ltd. under the Term Loan Agreement dated
January 30, 2004 (filed as Exhibit 99.2 to the Registrant’s
Current Report on Form 8-K (Date of Event:
January 30, 2004) filed May 10, 2004 and incorporated
herein by reference).
|
||
10.13
|
—
|
Term
Loan Agreement dated as of February 2, 2004 among Noble Energy
Mediterranean Ltd., as borrower, Bank One, NA, as agent for the lenders,
and certain commercial lending institutions, as lenders (filed as
Exhibit 99.3 to the Registrant’s Current Report on Form 8-K
(Date of Event: January 30, 2004) filed May 10, 2004
and incorporated herein by reference).
|
||
10.14
|
—
|
Guaranty
of the Company dated February 2, 2004 guaranteeing obligations
of Noble Energy Mediterranean, Ltd. under the Term Loan Agreement dated
February 2, 2004 (filed as Exhibit 99.4 to the Registrant’s
Current Report on Form 8-K (Date of Event:
January 30, 2004) filed May 10, 2004 and incorporated
herein by reference).
|
||
10.15
|
—
|
Term
Loan Agreement dated as of February 4, 2004 among Noble Energy
Mediterranean Ltd., as borrower, The Royal Bank of Scotland Finance
(Ireland), as agent for the lenders and as the initial lender (filed as
Exhibit 99.5 to the Registrant’s Current Report on Form 8-K
(Date of Event: January 30, 2004) filed May 10, 2004
and incorporated herein by reference).
|
||
10.16
|
—
|
Guaranty
of the Company dated February 4, 2004 guaranteeing obligations
of Noble Energy Mediterranean, Ltd. under the Term Loan Agreement dated
February 4, 2004 (filed as Exhibit 99.6 to the Registrant’s
Current Report on Form 8-K (Date of Event:
January 30, 2004) filed May 10, 2004 and incorporated
herein by reference).
|
||
10.17*
|
—
|
Form of
Performance Units Agreement under the Noble Energy, Inc. 2004
Long-Term Incentive Plan (filed as Exhibit 10.3 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).
|
||
10.18
|
—
|
$2.1 billion
Five-Year Credit Agreement, dated December 9, 2005, 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. and Citibank, N.A.,
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: December 9, 2005),
filed December 14, 2005 and incorporated herein by
reference).
|
||
10.19
|
—
|
$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).
|
||
10.20*
|
—
|
Noble
Energy, Inc. 2005 Non-Employee Director Fee Deferral Plan, dated
December 11, 2008, and effective as of January 1, 2009, filed
herewith.
|
||
10.21*
|
—
|
Consulting
Agreement, dated May 9, 2005 but commencing May 16, 2005, by and
between Noble Energy, Inc. and Thomas J. Edelman (filed as
Exhibit 10.1 to the Registrant’s Current Report on Form 8-K
(Date of Event: May 16, 2005), filed May 20, 2005 and
incorporated herein by reference).
|
||
10.22*
|
—
|
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).
|
||
10.23*
|
—
|
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).
|
||
10.24*
|
—
|
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).
|
||
10.25*
|
—
|
Form of
Restricted Stock Agreement under the Noble Energy, Inc. 1992 Stock
Option and Restricted Stock Plan entered into by certain executive
officers and key employees of the Company on May 16, 2005 and
August 1, 2005, respectively (filed as Exhibit 10.4 to the
Registrant’s Quarterly Report on Form 10-Q for the quarter ended
June 30, 2005 and incorporated herein by reference).
|
||
10.26*
|
—
|
Noble
Energy, Inc. 1992 Stock Option and Restricted Stock Plan (as
amended through April 24, 2007), (filed as exhibit 10.1 to Registrant’s
Current Report on Form 8-K (Date of Event: April 24, 2007) filed April 30,
2007 and incorporated herein by reference).
|
Exhibit
Number
|
Exhibit**
|
|||
10.27*
|
—
|
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).
|
||
10.28*
|
—
|
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).
|
||
10.29*
|
—
|
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).
|
||
10.30*
|
—
|
Amendment
to the 2006 Performance Units Agreement (as amended effective January 1,
2008), (filed as Exhibit 10.43 to the Registrant’s Annual Report on
Form 10-K for the year ended December 31, 2007 and
incorporated herein by reference).
|
||
10.31*
|
—
|
Noble
Energy, Inc. 2005 Deferred Compensation Plan (as amended effective
January 1, 2009), filed herewith.
|
||
10.32*
|
—
|
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).
|
||
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).
|
||
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).
|
||
32.1
|
—
|
Certification
of the Company’s Chief Executive Officer Pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
|
||
32.2
|
—
|
Certification
of the Company’s Chief Financial Officer Pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
|
||
99.1
|
—
|
Report
of Independent Public Accounting Firm—PricewaterhouseCoopers LLP, filed
herewith.
|
||
99.2
|
—
|
Report
of Netherland, Sewell & Associates, Inc., filed
herewith.
|
||
*
|
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)
|
MBbls
|
Thousand
barrels
|
MMBbls
|
Million
barrels
|
Bpd
|
Barrels
per day
|
Bopd
|
Barrels
oil per day
|
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
|
MBoe
|
Thousand
barrels oil equivalent
|
MMBoe
|
Million
barrels oil equivalent
|
Boepd
|
Barrels
oil equivalent per day
|
MMgal
|
Million
gallons
|
KW
|
Kilowatt
|
KWh
|
Kilowatt
hours
|
MW
|
Megawatt
|
GW
Mcf
|
Gigawatt
Thousand
cubic feet
|
MMcf
|
Million
cubic feet
|
Bcf
|
Billion
cubic feet
|
Tcf
|
Trillion
cubic feet
|
Mcfpd
|
Thousand
cubic feet per day
|
MMcfpd
|
Million
cubic feet per day
|
Mcfe
|
Thousand
cubic feet equivalent
|
MMcfe
|
Million
cubic feet equivalent
|
Bcfe
|
Billion
cubic feet equivalent
|
BTU
|
British
thermal unit
|
MMBtu
|
Million
British thermal units
|
MMBtupd
|
Million
British thermal units per day
|
Btupcf
|
British
thermal unit per cubic foot
|
MT
|
Metric
tons
|
MTpd
|
Metric
tons per day
|
LNG
|
Liquefied
natural gas
|
LPG
|
Liquefied
petroleum gas
|
NGL
|
Natural
gas liquid
|