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100 Glenborough Drive
Suite 100
Houston, TX 77067-3610
nobleenergyinc.com
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Noble Energy,Inc.
07
P O R T
A N N U A
L
R E
19316easD1R2.qxp 3/7/08 6:48 PM Page 2
DIRECTORS
CHARLES D. DAVIDSON (4)
Chairman of the Board, President and Chief Executive Officer, Noble Energy, Inc.
JEFFREY L. BERENSON (2) (3)
President and Chief Executive Officer, Berenson & Company
MICHAEL A. CAWLEY (1) (3)
Trustee, President and Chief Executive Officer, The Samuel Roberts Noble Foundation, Inc.
EDWARD F. COX (2) (3) (4)
Partner, law firm of Patterson Belknap Webb & Tyler LLP
THOMAS J. EDELMAN (4)
Former Chairman of the Board and Chief Executive Officer, Patina Oil & Gas Corporation
KIRBY L. HEDRICK (2) (3) (4)
Former Executive Vice President, Phillips Petroleum Company
SCOTT D. URBAN (1) (3) (4)
Former Group Vice President, BP
WILLIAM T. VAN KLEEF (1) (3)
Former Executive Vice President and Chief Operating Officer, Tesoro Corporation
COMMITTEE MEMBERSHIP
Audit Committee
(1)
(2)
(3)
(4)
Compensation, Benefits and Stock Options Committee
Corporate Governance and Nominating Committee
Environment, Health and Safety Committee
EXECUTIVE OFFICERS
CHARLES D. DAVIDSON
Chairman of the Board, President, Chief Executive Officer and Director
ALAN R. BULLINGTON
Senior Vice President, International
SUSAN M. CUNNINGHAM
Senior Vice President, Exploration
ARNOLD J. JOHNSON
Vice President, General Counsel and Secretary
A. LEE ROBISON
DAVID L. STOVER
CHRIS TONG
Vice President, Human Resources
Executive Vice President and Chief Operating Officer
Senior Vice President and Chief Financial Officer
The Annual Meeting of Stockholders of Noble Energy, Inc. will be held on Tuesday, April 22,
2008, at 9:30 a.m., Central Time, at the Marriott Woodlands Waterway Hotel and Convention
Center located at 1601 Lake Robbins Drive, The Woodlands, Texas 77380. All stockholders
Houston, Texas 77067-3610
CORPORATE INFORMATION
ANNUAL MEETING
are cordially invited to attend.
FORM 10-K
The Company’s Annual Report on Form 10-K for the year ended December 31, 2007, as
filed with the Securities and Exchange Commission, is included in this report. Additional
copies are available without charge upon request by writing to Investor Relations, Noble
Energy, Inc., 100 Glenborough Drive, Suite 100, Houston, Texas 77067-3610, via the
Company’s Internet website: http://www.nobleenergyinc.com, or via the Securities
and Exchange Commission’s Internet website: http://www.sec.gov.
FORWARD-LOOKING STATEMENT
This 2007 Annual Report to stockholders contains forward-looking statements based on
expectations, estimates and projections as of the date of this report. These statements by
their nature are subject to risks, uncertainties and assumptions and are influenced by
various factors. As a consequence, actual results may differ materially from those expressed
in the forward-looking statements. For more information, see “Item 1A. Risk Factors.
Disclosure Regarding Forward-Looking Statements” in Noble Energy’s Form 10-K included
in this report.
NOBLE ENERGY, INC.
Corporate Headquarters
100 Glenborough Drive
Suite 100
(281) 872.3100
INVESTOR RELATIONS
David Larson
Vice President, Investor Relations
(281) 872.3100
Investor_Relations@nobleenergyinc.com
www.nobleenergyinc.com
INDEPENDENT PUBLIC ACCOUNTANTS
KPMG LLP
TRANSFER AGENT AND REGISTRAR
Wells Fargo Bank N.A.
Shareowner Services
161 North Concord Exchange
South St. Paul, MN 55075-1139
(800) 468.9716
stocktransfer@wellsfargo.com
COMMON STOCK LISTED
NEW YORK STOCK EXCHANGE
Symbol - NBL
19316easD2R3.p1.ps 3/7/08 9:54 AM Page 1
Built to be Durable
We adhere to a simple yet consistent
business model that is designed to
withstand the ever-changing energy
industry. The key components of our
model are:
▲▲ a foundation of high-quality,
long-lived assets,
▲▲ near-term growth from
high-return, lower risk
development projects and
▲▲ focused exploration on
meaningful opportunities.
19316easD2R3.p2.ps 3/7/08 9:54 AM Page 2
Next Level Thinking
We empower our employees to work and
think creatively in order to foster ahead-
of-the-curve ideas. Our commitment to the
application of new business intelligence
and technologies has resulted in improved
resource predictability from exploration
processes, increased efficiencies in drilling
techniques and enhanced oil and natural
gas recoveries in producing fields.
19316easD2R2.qxp 3/5/08 8:06 PM Page 3
2008 CAPITAL PROGRAM
ROCKIES 20%
OTHER U.S. 9%
W. AFRICA 9%
WATTENBERG 26%
OTHER INTERNATIONAL 4%
DEEPWATER U.S. 19%
NORTH SEA/ISRAEL 11%
CORPORATE 2%
19316easD2R2.qxp 3/5/08 8:06 PM Page 4
Potential
Access to new hydrocarbon resources is a
critical element for organic growth. Our exploration
success in West Africa and the deepwater Gulf
of Mexico, combined with a huge inventory of
development projects in onshore basins of the U.S.,
creates tremendous possibilities for the future.
19316easD2R3.p5.ps 3/7/08 9:54 AM Page 5
In October 2007,
Standard & Poor’s added
Noble Energy to the S&P 500,
a group of leading companies in
numerous U.S. industries.
19316easD2R2.qxp 3/5/08 8:06 PM Page 6
Expand
We extend our asset portfolio
with selective property and corporate
acquisitions, while our new ventures team
searches for new opportunities worldwide. Our
acreage positions in the New Albany shale, Piceance
basin and Niobrara plays continue to build as they
develop into core areas. Exploration prospects
offshore Israel and Suriname are also
important in broadening our portfolio.
19316easD2R2.qxp 3/5/08 8:06 PM Page 7
L E T T E R T O S H A R E H O L D E R S
2007 was a special year for Noble Energy in many ways. We had the opportunity to
celebrate our company’s 75th anniversary as we looked back with pride on the many
accomplishments since our founding by Lloyd Noble in 1932. We also celebrated the
many financial and operational successes of 2007. Our shareholders participated in
our success, as our share price increased 62 percent during the year. Additionally,
Noble Energy’s growth and performance resulted in our addition to the prestigious
S&P 500 index during the year.
It was clearly a year of tremendous accomplishments. We achieved record earnings
totaling approximately $944 million, a 39 percent increase over our previous record
in 2006. It was also a year of record volumes which averaged 199 thousand barrels
of oil equivalent per day (MBoepd), a 13 percent increase over 2006 after adjusting
for the company’s sale of the Gulf of Mexico shelf assets. We continued to focus on
cost efficiency throughout our business, allowing us once again to keep our unit cash
costs in the best quartile among our peers. Our proven reserves at the end of 2007
reached a record of 880 million barrels of oil equivalent (MMBoe), up over five
percent from the prior year. During 2007, we invested $1.7 billion in exploration and
development projects, allowing us to replace 166 percent of our volumes with new
reserves at under $15 per barrel of oil equivalent (BOE).
19316easD2R2.qxp 3/5/08 8:06 PM Page 8
2007 SALES VOLUMES
Rocky Mountains 26%
Deepwater U.S. 12%
Other U.S. 17%
West Africa 23%
North Sea/Israel 16%
Other International 6%
We achieved a number of key objectives related to our
exploration and production programs. Early in the
year, we resumed our West Africa exploration program
after waiting for over a year on the upgrade of a
deepwater drillship.The 2007 exploration program in
West Africa was one of the most significant in our
company’s history and resulted in six successful wells
out of seven drilled. At the end of this program, we
not only appraised our 2005 Belinda discovery, but
also discovered the Benita, Yolanda and Yoyo fields.
Belinda, Benita and Yolanda are located in Equatorial
Guinea and Yoyo is located just across the border
in Cameroon. These new fields will be an important
part of our growth for many years to come.
Other important 2007 events that occurred in our
international business included initial gas sales to a
new liquefied natural gas (LNG) plant in Equatorial
Guinea and the startup of the Dumbarton field in the
North Sea. In addition, our natural gas sales in Israel
grew 19 percent in 2007 and has grown every year
since we started producing in 2004.
In the United States (U.S.), we continued a very active
investment program in the Rocky Mountains.
Wattenberg, our largest onshore field, contains an
inventory of thousands of lower risk development
projects, allowing us to grow its production and
proven reserves. Elsewhere in the Rocky Mountains,
we accelerated the drilling programs in the Piceance
basin and Niobrara plays. Both areas showed
significant drilling success, and we are expecting more
growth in 2008. We continued our exploration and
development work in the deepwater Gulf of Mexico.
During the year, we carried out a number of projects
at our existing deepwater fields that not only helped
maintain their production, but also added new
resources. With our partner, we discovered Isabela in
the deepwater offshore Louisiana. Following the
discovery, we acquired offset acreage and are planning
additional drilling in 2008. We were also a successful
bidder in the 2007 Central Gulf lease sale, allowing us
to add several deepwater prospects to our inventory.
Our overall business model remains unchanged. It is
simple and designed to help Noble Energy thrive in a
variety of environments.The foundation is a portfolio
of high-quality assets that are efficient and long-lived
producers, yield high investment returns, and/or
possess large inventories of future development
opportunities. These lower risk development projects
generate sustainable and durable near-term growth.
Our exploration program has evolved into one that is
almost entirely focused on significant and high impact
opportunities. We supplement our portfolio with
acquisitions of both producing properties and
prospective acreage. This business model allows us to
maintain capital discipline, while still growing our
company. In times of strong commodity prices, it
allows us to generate free cash flow to maintain our
financial strength and provides substantial capacity to
fund unique and unanticipated opportunities.
As we make plans to move Noble Energy to the next
level of performance, our thoughts center on how to
further improve our portfolio and processes. The
energy industry is in a very dynamic period where
innovative ideas are constantly opening up new areas
for growth. We pursue a diversified portfolio of assets
balanced between U.S. and international operating
areas. We are also looking for opportunities to add to
this portfolio and dispose of assets that are no longer
core to us. Over the past year, we have expanded our
U.S. positions in the New Albany shale, Piceance
basin and Niobrara plays and announced the sale of
our properties in Argentina – all changes that are
consistent with our overall portfolio management
strategies. Our exploration processes continue to
evolve and improve through the application of better
techniques and new technology. This has given us the
confidence to grow our exploration program, leading
19316easD2R2.qxp 3/5/08 8:06 PM Page 9
-
2007 RESERVES
U.S. Liquids 23%
U.S. Gas 35%
International Liquids 14%
International Gas 28%
us to incredible success in West Africa this past year.We
have built a new ventures program that is designed to
leverage our exploration expertise by identifying
growth opportunities, sometimes in areas virtually
unexplored by our industry.“Next level” thinking also
applies to new drilling techniques.We have identified
and applied best drilling practices, allowing us to
substantially reduce costs and/or improve well
performance. Once again, our West Africa drilling
program provides a significant example where the
drilling time to target depth was reduced by 50
percent, yielding substantial savings in drilling costs. In
the Wattenberg field, we began testing a new drilling
technique utilizing coiled tubing that reduced drilling
times for new wells by almost half. In the Piceance
basin, we are using rigs that are better able to drill
multiple wells off single drill pads, thus reducing time,
cost and environmental impact. We are also making
significant investments in new business systems that
give us better efficiency and flexibility as we account
for and analyze our performance.
Our programs for 2008 are expected to build on the
solid foundation established in 2006 and 2007. Our
capital investment program for 2008 has been set at
$1.6 billion and focuses on our core areas that have
yielded our growth in recent years. Approximately
three-quarters of our capital will be directed towards
development projects and one-quarter to exploration.
In the Rocky Mountains, we again plan to invest
heavily in the Wattenberg, Piceance and Niobrara
areas to take advantage of their huge inventories of
lower risk development projects. We also plan to
further test our New Albany shale acreage in Southern
Indiana, where we recently brought new wells on
production. In the deepwater Gulf of Mexico, we
plan to participate in several exploration prospects
and bring on new production at South Raton
and Ticonderoga. We are planning for ongoing
development work at our core Mid-continent fields
and for the expansion of our drilling programs in
East Texas.
Our international investment program will remain
active in 2008. As a follow-up to the outstanding
exploration success we experienced in West Africa in
2007, we are planning for further appraisal and
exploration drilling this year, as well as beginning
the important engineering work necessary to prepare
for the development of our recent discoveries there.
In addition, we are planning to test important
exploration prospects offshore Israel and Suriname. It
will be Noble Energy’s first well in Suriname. In
Equatorial Guinea, we expect continued production
growth in 2008 as a result of a full year of natural gas
sales to the LNG plant. In late 2007, we approved the
next phase of development of the Dumbarton field in
the North Sea. Israel is continuing to build its natural
gas pipeline infrastructure,
thus expanding our
customer base and increasing the demand for natural
gas. Also scheduled for approval in 2008 is the
expansion of the Cheng Dao Xi field in the Bohai Bay
of China.This will be the first major expansion of the
field since it first started up in early 2003.
We are pleased with our performance and are truly
excited about what the future holds for Noble Energy.
Our underlying asset portfolio shows great strength
and durability as it provides strong production and
a large inventory of investment opportunities. We
continue to build our exploration inventory by
seeking out new areas that will benefit from the
application of innovative technology and processes. At
the same time, we remain receptive to new ideas and
opportunities that will help propel us to the next level
of performance. We have come a long way in a very
short period of time, but there is tremendous potential
to further expand in the future.
19316easD2R3.p10.ps 3/7/08 7:39 AM Page 10
ANNUAL NET INCOME (in millions)
ANNUAL SALES VOLUMES (MMBoe)
1000
800
600
400
200
0
80
70
60
50
40
30
20
10
0
03
04
05
06
07
03
04
05
06
07
Our progress and performance is clearly the result
of incredible dedication and hard work exhibited by
our employees. Noble Energy employees remain
committed to efficiently finding, developing and
producing important energy supplies, while providing
superior returns to our shareholders.These employees
are also dedicated to minimizing the impacts on the
environment, preserving the safety of all involved and
complying with complex laws and regulations. I could
not be more proud of their significant achievements,
and how they conduct Noble Energy’s business
throughout the world.
We offer our thanks to Bruce A. Smith, who resigned
from our board in 2008. Bruce joined the board in
2002 and was extremely helpful as we took Noble
Energy through an important transformation in recent
years.We welcome Scott D. Urban to our board. Scott
joined us in 2007 and was previously an executive
with Amoco and its successor BP.
On a final note, all of us at Noble Energy mourn the
sudden and tragic passing of Robert K. Burleson,
our Senior Vice President of Administration and
Marketing. Bob is greatly missed as a friend as well as
a significant contributor to our company. 2007 also
saw the passing of Mary Jane Noble, wife of the late
Sam Noble. As we complete our 75th year, we are
reminded of the immense legacy the Noble family has
left us.
On behalf of the Board of Directors and our
employees, I want to thank all of our stakeholders
for their continued confidence and support of
Noble Energy.
CHARLES D. DAVIDSON
CHAIRMAN OF THE BOARD
PRESIDENT AND CHIEF EXECUTIVE OFFICER
19316easD2R3.p11.ps 3/7/08 7:39 AM Page 11
OPERATING & FINANCIAL DATA - 2007 ANNUAL REPORT
OPERATING DATA
2007
2006
2005
2004
2003
YEAR-END PROVED RESERVES
Natural Gas (Bcf)
3,307
3,231
3,091
1,987
1,642
Liquids (MMBbls)
Total (MMBoe)
SALES VOLUMES
Natural Gas (Bcf)
Liquids (MMBbls) [1]
Total (MMBoe)
AVERAGE SALES PRICES
Natural Gas (per Mcf)
Crude Oil (per Bbl) [2]
FINANCIAL DATA
(In millions, except per share amounts and ratios)
Revenues
Net Income
Earnings per Common Share Diluted
Weighted Average
Common Shares Diluted
Cash Dividend per Common Share
Net Cash Provided by
Operating Activities
Capital Expenditures [3]
Total Assets
Total Debt
Stockholders’ Equity
Total Debt-to-Book-Capital Ratio
Total Debt per BOE
329
880
251
31
73
5.26
60.61
2007
3,272
944
5.45
173
0.44
2,017
1,739
10,831
1,876
4,809
28%
$
$
$
$
$
$
$
$
$
$
296
835
227
30
68
5.55
54.47
2006
2,940
678
3.79
179
0.28
1,730
1,347
9,589
1,801
4,134
30%
291
806
186
22
53
5.78
45.35
2005
2,187
646
4.12
157
0.15
1,240
890
8,878
2,031
3,090
40%
$
$
$
$
$
$
$
$
$
$
293
525
134
17
39
4.76
34.48
2004
1,351
329
2.78
118
0.10
708
629
3,436
880
1,460
38%
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2.13
$
2.16
$
2.52
$
1.68
$
$
$
$
$
$
$
$
$
$
$
$
$
183
457
123
13
34
4.19
27.67
2003
1,008
78
0.68
115
0.09
603
502
2,821
930
1,074
42%
2.04
[1] Includes Sales from Equity Investee Condensate and Liquified Petroleum Gas (LPG).
[2] Excludes Equity Investee Condensate and LPG Sales Volumes and Prices.
[3] Excludes Corporate Acquisitions.
19316easD2R2.qxp 3/5/08 8:06 PM Page 12
SEVENTY
F-
19 32
Lloyd Noble forms Samedan
Oil Corporation,named after
his children,Sam,Ed and Ann
19 68
Samedan acquires its
first offshore block in the
Gulf of Mexico
19 69
Noble Affiliates,Inc.is organized
combining several companies,the
primary two being Noble Drilling
Corporation and Samedan
19 91
First production occurs
from the Alba field,offshore
Equatorial Guinea
19 72
Begins trading as a public
company on NASDAQ
19 96
Acquires Energy Development
Company,adding a diverse group
of U.S.and international assets
19 80
Moves to the New York Stock
Exchange and begins trading
under the symbol NBL
20 00
Mari-B discovery is
announced off the coast
of Israel
19 85
Spins off drilling subsidiary,
Noble Drilling Corporation
20 01
First operated deepwater
Gulf of Mexico discovery
at Lost Ark is announced
20 01
Methanol production
commences at the Atlantic
Methanol Production Company
plant in Equatorial Guinea
20 02
First production occurs from the
gas-to-power project in Ecuador
19316easD2R2.qxp 3/5/08 8:06 PM Page 13
IVE YEARS
20 06
Acquires U.S.Exploration Holdings,
Inc.,expanding position in the
Wattenberg field
20 07
Dumbarton commences
production in the North Sea
using a floating production,
storage and offloading facility
20 02
Noble Affiliates,Inc.changes its
name to Noble Energy,Inc.
20 07
Benita discovery is announced
on Block “I”offshore
Equatorial Guinea
20 04
Natural gas sales begin in Israel
20 07
Yoyo discovery is announced
on the PH-77 license
offshore Cameroon
20 05
Acquires Patina Oil & Gas,
enhancing onshore U.S.
asset portfolio
20 07
Yolanda discovery is announced on
Block “I”offshore Equatorial Guinea
20 05
Belinda discovery is
announced on Block “O”
offshore Equatorial Guinea
20 06
Significant presence is established
in deepwater Gulf of Mexico with
production at Swordfish,Lorien
and Ticonderoga
20 06
Noble Energy sells Gulf of Mexico
shelf assets
19316easD2R2.qxp 3/5/08 8:06 PM Page 14
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
⌧
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2007
or
(cid:134)
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number: 001-07964
NOBLE ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware
(State of incorporation)
100 Glenborough Drive, Suite 100
Houston, Texas
(Address of principal executive offices)
73-0785597
(I.R.S. employer identification number)
77067
(Zip Code)
(281) 872-3100
(Registrant’s telephone number, including area code)
Securities registered pursuant to section 12(b) of the Act:
Title of each class
Common Stock, $3.33-1/3 par value
Preferred Stock Purchase Rights
Name of each exchange on which registered
New York Stock Exchange
New York Stock Exchange
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. ⌧ Yes (cid:134) No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the
Act. (cid:134) Yes ⌧ No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ⌧ Yes (cid:134) No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained
herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ⌧
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated
filer or a smaller reporting company. See definitions of “accelerated filer”, “large accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ⌧
Smaller reporting company (cid:134)
Accelerated filer (cid:134)
(Do not check if a smaller reporting company)
Non-accelerated filer (cid:134)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).(cid:134) Yes ⌧ No
Aggregate market value of Common Stock held by nonaffiliates as of June 29, 2007: $10,563,558,607.
Number of shares of Common Stock outstanding as of February 12, 2008: 171,835,490.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2008 Annual Meeting of Stockholders to be held on
April 22, 2008, which will be filed with the Securities and Exchange Commission within 120 days after December 31,
2007, are incorporated by reference into Part III.
TABLE OF CONTENTS
Part I
Items 1 and 2. Business and Properties.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Risk Factors. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1A.
Unresolved Staff Comments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1B.
Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 3.
Submission of Matters to a Vote of Security Holders. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 4.
Executive Officers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Part II
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Management’s Discussion and Analysis of Financial Condition and Results of Operations. . . .
Quantitative and Qualitative Disclosures About Market Risk. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial Statements and Supplementary Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.. . .
Controls and Procedures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Information. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Part III
Directors, Executive Officers and Corporate Governance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Executive Compensation.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . . . .
Principal Accounting Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Part IV
1
17
22
22
22
23
25
27
28
50
51
104
104
105
106
106
106
106
106
Item 15.
Exhibits, Financial Statements Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
106
Items 1 and 2. Business and Properties.
PART I
This Annual Report on Form 10-K and the documents incorporated herein by reference contain forward-looking
statements based on expectations, estimates and projections as of the date of this filing. These statements by their
nature are subject to risks, uncertainties and assumptions and are influenced by various factors. As a consequence,
actual results may differ materially from those expressed in the forward-looking statements. For more information,
see Item 1A. Risk Factors—Disclosure Regarding Forward-Looking Statements of this Form 10-K.
General
Noble Energy, Inc. (“Noble Energy”, “we” or “us”) is a Delaware corporation, formed in 1969, that has been
publicly traded on the New York Stock Exchange (“NYSE”) since 1980. We are an independent energy company
that has been engaged in the acquisition, exploration, development, production and marketing of crude oil and
natural gas since 1932. In this report, unless otherwise indicated or where the context otherwise requires,
information includes that of Noble Energy and its subsidiaries. Exploration activities include geophysical and
geological evaluation and exploratory drilling on properties for which we have exploration rights. We operate
throughout major basins in the United States (“US”) including Colorado’s Wattenberg field and Piceance basin, the
Mid-continent area of western Oklahoma and the Texas Panhandle, the San Juan basin in New Mexico, the Gulf
Coast and the deepwater Gulf of Mexico. In addition, we conduct business internationally in China, Ecuador, the
Mediterranean Sea, the North Sea, West Africa (Equatorial Guinea and Cameroon) and in other areas.
Strategy
We are a worldwide producer of crude oil and natural gas. Our strategy is to achieve growth in earnings and cash
flow through the development of a high quality portfolio of producing assets that is balanced between US and
international projects. Strategic acquisitions (Patina Oil & Gas Corporation (“Patina”) in 2005 and U.S. Exploration
Holdings, Inc. (“U.S. Exploration”) in 2006), along with additional capital investment have resulted in substantial
growth in the last five years. Acquisitions and capital investment, combined with the sale of non-core assets, have
allowed us to achieve a strategic objective of enhancing our US asset portfolio, resulting in a company with assets
and capabilities that include growing US basins coupled with a significant portfolio of international properties.
Crude oil and natural gas sales volumes have doubled since 2003. Our reserve base, which includes both US and
international sources at 58% US and 42% international, has almost doubled in the same period. We are now a larger,
more diversified company with greater opportunities for both US and international growth. See Item 6. Selected
Financial Data for additional financial and operating information for fiscal years 2003-2007.
Proved Reserves
As of December 31, 2007, we had estimated proved reserves of 3.3 Tcf of natural gas and 329 MMBbls of crude oil.
On a combined basis, these proved reserves were equivalent to 880 MMBoe, an increase of 5% over the prior year.
At December 31, 2007, 74% of reserves were proved developed reserves.
1
Proved reserves estimates at December 31, 2007 were as follows:
United States
Natural gas (Bcf)
Crude oil (MMBbls)
Total US (MMBoe)
International
Natural gas (Bcf)
Crude oil (MMBbls)
Total International (MMBoe)
Worldwide
Natural gas (Bcf)
Crude oil (MMBbls)
Total Worldwide (MMBoe)
Proved
Developed
Reserves
December 31, 2007
Proved
Undeveloped
Reserves
Total
Proved
Reserves
1,259
129
339
1,297
100
316
2,556
229
655
581
78
175
170
22
50
751
100
225
1,840
207
514
1,467
122
366
3,307
329
880
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which
geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is
made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not
on escalations based upon future conditions. For additional information regarding estimates of crude oil and natural
gas reserves, including estimates of proved and proved developed reserves, the standardized measure of discounted
future net cash flows, and the changes in discounted future net cash flows, see Item 8. Financial Statements and
Supplementary Data—Supplemental Oil and Gas Information (Unaudited) and Item 7. Management’s Discussion
and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—
Reserves.
Engineers in our Houston, Denver and London offices prepare all reserve estimates for our different geographical
regions. These reserve estimates are reviewed and approved by senior engineering staff and division management
with final approval by the Director of Asset Development and certain members of senior management. During each
of the years 2007, 2006 and 2005, we retained Netherland, Sewell & Associates, Inc. (“NSAI”), independent third-
party reserve engineers, to perform reserve audits of proved reserves. A “reserve audit”, as we use the term, is a
process involving an independent third-party engineering firm’s visits, collection of any and all required geologic,
geophysical, engineering and economic data, and such firm’s complete external preparation of reserve estimates.
Our use of the term “reserve audit” is intended only to refer to the collective application of the procedures which
NSAI was engaged to perform. The term “reserve audit” may be defined and used differently by other companies.
The reserve audit for 2007 included a detailed review of 16 of our major international, deepwater Gulf of Mexico
and US fields, which covered approximately 71% of US proved reserves and 96% of international proved reserves
(81% of total proved reserves). The reserve audit for 2006 included a detailed review of 14 of our major
international, deepwater Gulf of Mexico and US fields, which covered approximately 80% of our total proved
reserves. The reserve audit for 2005 included a detailed review of 11 of our major international, deepwater Gulf of
Mexico and US fields, which covered approximately 72% of our total proved reserves.
In connection with the 2007 reserve audit, NSAI prepared its own estimates of our proved reserves. In order to
prepare its estimates of proved reserves, NSAI examined our estimates with respect to reserve quantities, future
producing rates, future net revenue, and the present value of such future net revenue. NSAI also examined our
estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X
Rule 4-10(a) and subsequent Securities and Exchange Commission (“SEC”) staff interpretations and guidance. In
the conduct of the reserve audit, NSAI did not independently verify the accuracy and completeness of information
and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of
operation and development, product prices, or any agreements relating to current and future operations of the fields
and sales of production. However, if in the course of the examination something came to the attention of NSAI
2
which brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such
information or data until it had satisfactorily resolved its questions relating thereto or had independently verified
such information or data. NSAI determined that our estimates of reserves conform to the guidelines of the SEC,
including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in
future years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(2) of
Regulation S-X. NSAI issued an unqualified audit opinion on our proved reserves at December 31, 2007, based
upon its evaluation. Its opinion concluded that our estimates of proved reserves were, in the aggregate, reasonable
and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles.
The fields that NSAI audits include our most significant fields and are chosen by senior engineering staff and
division management with final approval by the Director of Asset Development and certain members of senior
management. We usually include all deepwater Gulf of Mexico fields, all international fields that require reports by
requirement of the host government, all fields that require sanctioning by our Board of Directors, and other major
fields. No significant fields were excluded from the December 31, 2007 reserve audit.
When compared on a field-by-field basis, some of our estimates are greater and some are less than the estimates of
NSAI. Given the inherent uncertainties and judgments that go into estimating proved reserves, differences between
internal and external estimates are to be expected. On a quantity basis, the NSAI field estimates ranged from 21,966
MBoe above to 16,882 MBoe below as compared with our estimates. On a percentage basis, the NSAI field
estimates ranged from 9% above our estimates to 42% below our estimates. Differences between our estimates and
those of NSAI are reviewed for accuracy but are not further analyzed unless the aggregate variance is greater than
10%. At December 31, 2007, reserves differences, in the aggregate, were less than 13,200 MBoe, or 2%.
Since January 1, 2007, no crude oil or natural gas reserve information has been filed with, or included in any report
to any federal authority or agency other than the SEC and the Energy Information Administration (“EIA”) of the US
Department of Energy. We file Form 23, including reserve and other information, with the EIA.
Acquisition and Divestiture Activities
We maintain an ongoing portfolio optimization program. We may engage in acquisitions of additional crude oil or
natural gas properties and related assets through either direct acquisitions of the assets or acquisitions of entities
owning the assets. We may also divest non-core assets in order to optimize our property portfolio.
In December 2007, we entered into an agreement to sell our interest in Argentina for a sales price of $117.5 million,
effective July 1, 2007. We expect the sale, which is subject to regulatory and partner approvals, to close in 2008.
Crude oil reserves for the Argentina properties totaled 7 MMBbls at December 31, 2007.
In 2006, we sold all of our Gulf of Mexico shelf properties except for the Main Pass area, which is undergoing
redevelopment studies. As of the effective date of the sale, proved reserves for the Gulf of Mexico properties sold
totaled approximately 7 MMBbls of crude oil and 110 Bcf of natural gas. Deepwater Gulf of Mexico and Gulf Coast
onshore areas remain core areas and are more aligned with our long-term business strategies. See Item 8. Financial
Statements and Supplementary Data—Note 3—Acquisitions and Divestitures.
In 2006, we acquired U.S. Exploration, a privately held corporation, for $412 million plus liabilities assumed. U.S.
Exploration’s reserves and production are located in Colorado’s Wattenberg field. This acquisition significantly
expanded our operations in one of our core areas. Proved reserves of U.S. Exploration at the time of acquisition
were approximately 234 Bcfe, of which 38% of the reserves were proved developed and 55% of the reserves were
natural gas. Proved crude oil and natural gas properties were valued at $413 million and unproved properties were
valued at $131 million. See Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and
Divestitures.
In 2005, we acquired Patina through merger (“Patina Merger”) for a total purchase price of $4.9 billion. Patina’s
long-lived crude oil and natural gas reserves provide a significant inventory of low-risk opportunities that balanced
our portfolio. Patina’s proved reserves at the time of acquisition were estimated to be approximately 1.6 Tcfe, of
which 72% of the reserves were proved developed and 67% of the reserves were natural gas. Proved crude oil and
natural gas properties were valued at $2.6 billion and unproved properties were valued at $1.1 billion. See Item 8.
Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures.
3
Crude Oil and Natural Gas Properties and Activities
We search for crude oil and natural gas properties, seek to acquire exploration rights in areas of interest and conduct
exploratory activities. These activities include geophysical and geological evaluation and exploratory drilling, where
appropriate, on properties for which we have acquired exploration rights. Our properties consist primarily of
interests in developed and undeveloped crude oil and natural gas leases. We also own natural gas processing plants
and natural gas gathering and other crude oil and natural gas related pipeline systems.
United States
We have been engaged in crude oil and natural gas exploration, exploitation and development activities throughout
onshore US since 1932 and in the Gulf of Mexico since 1968. The Patina Merger and the acquisition of U.S.
Exploration have significantly increased the breadth of our onshore operations, especially in the Rocky Mountain
and Mid-continent areas. These two acquisitions have provided us with a multi-year inventory of exploitation and
development opportunities. In 2007, we continued to expand our acreage position with the acquisition of
approximately 290,000 net acres in the Piceance, Niobrara, and New Albany Shale areas. US operations accounted
for 58% of our 2007 consolidated sales volumes and 58% of total proved reserves at December 31, 2007.
Approximately 60% of the proved reserves are natural gas and 40% are crude oil. Our onshore US portfolio at
December 31, 2007 included 1,308,823 gross developed acres and 1,234,858 gross undeveloped acres. We also hold
interests in 97 offshore blocks in the Gulf of Mexico. In 2008, we plan to invest approximately $1.2 billion, or 74%,
of budgeted capital in the US.
Sales of production and estimates of proved reserves for our significant US operating areas were as follows:
Year Ended December 31, 2007
Sales Volumes
Natural Gas Crude Oil
(MBbls)
(MMcf)
Total
(MBoe)
Natural Gas
(Bcf)
December 31, 2007
Proved Reserves
Crude Oil
(MMBbls)
Total
(MMBoe)
Northern Region
Wattenberg
Piceance
Niobrara
Other
Total
Southern Region
Deepwater Gulf of Mexico
Mid-continent
Gulf Coast onshore and other
Total
Total United States
59,670
7,797
7,897
9,392
84,756
18,722
30,760
16,219
65,701
150,457
4,674
7
-
53
4,734
5,847
3,340
1,530
10,717
15,451
14,619
1,307
1,316
1,618
18,860
8,967
8,467
4,233
21,667
40,527
893
183
98
139
1,313
79
341
107
527
1,840
109
-
-
1
110
21
51
25
97
207
258
31
16
24
329
34
108
43
185
514
4
Additional information for our significant US operating areas is as follows:
Northern Region
Wattenberg
Piceance
Niobrara
Other
Total
Southern Region
Deepwater Gulf of Mexico
Mid-continent
Gulf Coast onshore and other
Total
Total United States
Year Ended
December 31, 2007
Gross Wells Drilled/
Participated in
December 31, 2007
Gross
Productive Wells
508
55
125
56
744
6
147
38
191
935
5,161
112
744
1,239
7,256
13
3,981
457
4,451
11,707
Northern Region—The Northern region consists of our operations in the Rocky Mountain area, which includes the
D-J (Wattenberg field), San Juan, Wind River, and Piceance basins, as well as the Niobrara, Bowdoin and Siberia
Ridge fields. The addition of Patina and U.S. Exploration assets, particularly in the Wattenberg field, combined with
our legacy operations in the Bowdoin field, the Niobrara trend, the Wind River basin and Piceance basin, have made
the Rocky Mountains one of our core operating areas. We are currently running 13 drilling rigs and 24
completion/workover units. We plan to invest approximately $744 million, or 62% of budgeted US capital in the
Northern region during 2008.
Wattenberg Field—The Wattenberg field (approximately 97% operated working interest), our largest US asset,
continues to grow production and reserves. In 2007, sales of production from this field accounted for 36% of total
US sales volumes. Wattenberg field proved reserves accounted for 50% of US proved reserves at December 31,
2007.
We acquired working interests in the Wattenberg field through the Patina Merger in 2005 and acquisition of U.S.
Exploration in 2006. Located in the D-J basin of north central Colorado, the Wattenberg field provides us with a
substantial future project inventory. One of the most attractive features of the field is the presence of multiple
productive formations, which include the Codell, Niobrara and J-Sand formations, as well as the D-Sand, Dakota
and the shallower Shannon, Sussex and Parkman formations.
Drilling in the Wattenberg field is considered lower risk from the perspective of finding crude oil and natural gas
reserves, with 99.8% of the wells drilled in 2007 encountering sufficient quantities of reserves to be completed as
economic producers. In May 1998, the Colorado Oil and Gas Conservation Commission (“COGCC”) adopted the
“Greater Wattenberg Area Special Well Location Rule 318A” which allows all formations in the Wattenberg field to
be drilled, produced and commingled from any or all of ten “potential drilling locations” on a 320-acre parcel. A
“commingled” well is one which produces crude oil from two or more formations or zones through a common string
of casing and tubing. In December 2005, the COGCC amended Rule 318A providing for an effective well density of
one well per 20 acres in a designated portion of the Greater Wattenberg Area to more effectively drain the reservoir.
The amendment applies only to the Niobrara, Codell and J-Sand formations and became effective in March 2006.
We are currently running seven drilling rigs and 17 completion units in the Wattenberg field. Our current field
activities are focused primarily on the development of J-Sand, Codell and Niobrara reserves through drilling new
wells or deepening within existing wellbores, recompleting the Codell formation within existing J-Sand wells,
refracturing or trifracturing existing Codell wells and refracturing or recompleting the Niobrara formation within
existing Codell wells. A refracture consists of the restimulation of a producing formation within an existing wellbore
to enhance production and add incremental reserves. A trifracture is effectively a refracture of a refracture. These
projects and continued success with our production enhancement program, which includes well workovers,
reactivations, and commingling of zones, allow us to increase production and add proved reserves to what is
considered a mature field. During 2007, we drilled or participated in 508 development wells, with a 99.8% success
5
rate, and added approximately 244 Bcfe of proved reserves in the Wattenberg field. Approximately 58% of these
reserve additions were natural gas. We also grew production from an average of 227 MMcfe per day for 2006 to 240
MMcfe per day for 2007. We plan to drill approximately 480 wells in 2008 (of which 337 will be combination
Codell/Niobrara new drills). We also plan to participate in 120 non-operated drilling projects in 2008. We have a
substantial project inventory remaining and plan to perform approximately 340 projects including refractures,
trifractures, and recompletions during 2008.
Other Rocky Mountain areas include:
Niobrara Trend—The Niobrara trend (approximately 87% operated working interest) is located in eastern Colorado
and extends into Kansas and Nebraska. During 2007, we expanded our acreage position with the acquisition of
160,000 net acres. We are currently running two drilling rigs and three completion units. During 2007, we drilled
or participated in 125 wells with a 79% success rate, and our activity resulted in the addition of 19 Bcfe of proved
reserves. We plan to drill 300 wells in 2008.
Piceance Basin—The Piceance basin in western Colorado (approximately 96% operated working interest) is another
rapidly growing area for us. During 2007, we added 10,500 net acres to our position. We are currently running four
drilling rigs and three completion units. We drilled or participated in 55 development wells during 2007, 100% of
which were successful, and our activity resulted in the addition of 83 Bcfe of proved reserves. We plan to drill over
100 wells during 2008.
Other—We are also active in the Bowdoin field (approximately 60% operated working interest), located in north
central Montana; the San Juan basin (approximately 81% operated working interest), located in northwestern New
Mexico and southwestern Colorado; and the Wind River basin (approximately 56% operated working interest),
located in central Wyoming. During 2007 we drilled or participated in a total of 56 development wells in these areas,
100% of which were successful. We plan to drill approximately 60 wells and recomplete 190 wells during 2008.
Southern Region—The Southern region includes the Gulf Coast onshore, West and East Texas, Louisiana, and the
deepwater Gulf of Mexico, as well as the Mid-continent area (the Texas Panhandle and parts of Oklahoma, Kansas,
Arkansas, Illinois and Indiana). The Gulf Coast and deepwater Gulf of Mexico are core US operating areas. During
2006, we sold all of our Gulf of Mexico shelf properties except for the Main Pass area. The sale of our shelf
properties allows us to migrate future investments and growth from the Gulf of Mexico shelf to the deepwater Gulf
of Mexico which we believe is an area of higher potential. We plan to invest approximately $460 million, or 38% of
budgeted US capital, in the Southern region during 2008, with approximately 67% in the deepwater Gulf of Mexico,
and the remainder to the Gulf Coast and the Mid-continent areas.
Deepwater Gulf of Mexico—Deepwater Gulf of Mexico accounted for 22% of 2007 US sales volumes and 7% of US
proved reserves at December 31, 2007. During 2007, we continued to focus on the growth of our deepwater Gulf of
Mexico business highlighted by a successful exploration discovery at Isabela and a successful sidetrack-appraisal
well at our 2006 Raton discovery. We also completed successful development drilling programs in our Ticonderoga
and Swordfish fields. Deepwater Gulf of Mexico activity resulted in proved reserve additions of 12 MMBoe during
2007. Participation in the 2007 Central Gulf of Mexico Outer Continental Shelf Sale resulted in our being awarded
eight new deepwater Gulf of Mexico leases totaling $50 million.
At year-end, development planning was underway for Isabela (Mississippi Canyon Block 562, 33% working
interest). We have also acquired an interest in adjacent acreage with additional exploration potential on Mississippi
Canyon Blocks 519 and 563 (23.25% working interest). We plan to drill a well on Block 519 (Santa Cruz Prospect)
in 2008 pending rig availability. In total there are three prospects on the combined leasehold that, conceptually,
would be co-developed in a subsea tieback to an existing production facility.
Other 2007 exploration drilling included the Mississippi Canyon Block 568 #1 (Robusto Prospect, 20% working
interest) and the East Breaks Block 465 #1 (Lost Ark South Prospect, 98.4% working interest), neither of which
encountered hydrocarbons in commercial quantities.
During 2007 we saw an extremely active deepwater Gulf of Mexico development program. At our Raton project in
Mississippi Canyon Block 248 (66.67% operated working interest), we successfully sidetracked and completed the
248 #1 discovery well drilled in 2006. At year-end the project had moved into the development stage and is slated
for subsea tieback and first production in the second quarter of 2008.
At our operated Swordfish project (85% working interest), we drilled and completed a sidetrack to Viosca Knoll
Block 917 #1 well and began gas production from this well at year end. At the Ticonderoga development in Green
6
Canyon Block 768 (50% working interest, non-operated), the #3 and #1 ST4 wells were drilled and completed to
extend and enhance production from the field. Both are slated for first production in the first quarter of 2008.
At the Lost Ark project in East Breaks Blocks 421 and 464 (48.4% operated working interest), the 421 #1 well,
which had reached the end of its productive life, was plugged and abandoned, and the 464 #1 well was completed
and put on production to develop the remaining reserves at the field.
We are currently evaluating a possible sidetrack-appraisal well to be drilled at the Raton South oil discovery in
Mississippi Canyon Block 292 during late 2008 (originally drilled in 2006). The Redrock natural gas/condensate
discovery, also drilled in 2006, is currently considered a co-development candidate to a successful sidetrack-
appraisal well at Raton South. Additional key exploration activity planned for 2008 includes a well at the
Mississippi Canyon Block 948, Gunflint prospect, (50% working interest), in the second half of 2008.
Mid-continent—A significant area of activity in Mid-continent is the Granite Wash development, located in the
Texas Panhandle. We drilled or participated in 53 development wells in 2007, 100% of which were successful. The
potential for horizontal drilling is currently being evaluated. Another significant area in Mid-continent is the
ongoing Southern Oklahoma development. In 2007 we drilled or participated in 45 wells resulting in additional
incremental production of 1,515 Boepd.
In addition, we continue to selectively increase our acreage position in resource plays, including shale plays. We
have accumulated over 179,000 acres in the New Albany Shale. During 2007, we drilled 16 New Albany Shale
wells. Currently nine are producing and seven are in the progress of pipeline connection. The Paxton facility, which
we operate, will serve the majority of wells in the Paxton field. We plan to have an active drilling program during
2008.
Other Mid-continent areas include parts of Texas, Oklahoma, Kansas, Illinois, Indiana and Arkansas. During 2007,
we drilled or participated in a total of 33 wells. We plan to drill or participate in 60 wells in the Mid-continent area
during 2008.
Gulf Coast Onshore—During late 2007, we began a six well program at Oliver Creek in Shelby County, Texas to
develop the Travis Peak reservoir as well as test deeper Cotton Valley horizons. We have completed one Travis
Peak well and are currently completing the second Travis Peak well. The deeper Cotton Valley horizons are being
tested in two additional wells currently being drilled or completed. Two additional wells remain in the current six
well program. Additional drilling is planned for later in 2008.
International
International operations are significant to our business, accounting for 42% of consolidated sales volumes in 2007
and 42% of total proved reserves at December 31, 2007. International proved reserves are approximately 67%
natural gas and 33% crude oil. Operations in Equatorial Guinea, Cameroon, Ecuador, China and Suriname are
conducted in accordance with the terms of production sharing contracts. In 2008, we plan to invest approximately
$392 million, or 24%, of budgeted capital in our international locations.
7
Additional information for our significant international operating areas is as follows:
Year Ended December 31, 2007
Sales Volumes
Natural Gas Crude Oil
(MBbls)
(MMcf)
Total
(MBoe)
Natural Gas
(Bcf)
December 31, 2007
Proved Reserves
Crude Oil
(MMBbls)
Total
(MMBoe)
International
West Africa
North Sea
Israel
Ecuador
China
Argentina
Total consolidated
Equity investees:
Condensate (MBbls)
LPG (MBbls)
Total
Equity investee share of
methanol sales (Kgal)
48,349
2,276
40,449
9,385
-
-
100,459
-
-
100,459
5,500
4,564
-
-
1,402
1,034
12,500
670
2,135
15,305
13,558
4,943
6,742
1,564
1,402
1,034
29,243
670
2,135
32,048
160,540
941
19
319
188
-
-
1,467
82
25
-
-
8
7
122
239
28
53
31
8
7
366
Wells drilled in 2007 and productive wells at December 31, 2007 in our international operating areas were as
follows:
International
West Africa
North Sea
Israel
Ecuador
China
Argentina
Total International
Year Ended
December 31, 2007
Gross Wells
Drilled/Participated in
December 31, 2007
Gross
Productive Wells
7
2
1
-
-
50
60
20
22
8
5
16
732
803
West Africa (Equatorial Guinea and Cameroon)—Operations in West Africa accounted for 46% of 2007
consolidated international sales volumes and 65% of international proved reserves at December 31, 2007. At
December 31, 2007, we held 45,203 gross developed acres and 850,197 gross undeveloped acres in Equatorial
Guinea and 1,125,000 gross undeveloped acres in Cameroon.
We began investing in West Africa in the early 1990’s. Activities center around our 34% non-operated working
interest in the Alba field, offshore Equatorial Guinea, which is one of our most significant assets. Operations include
the Alba field and related production and condensate facilities, a methanol plant (located on Bioko Island), and an
onshore LPG processing plant where additional condensate is produced. The methanol plant was originally designed
to produce commercial grade methanol at a rate of 2,500 MTpd gross. As a result of various upgrade efforts, the
plant is now capable of producing up to 3,000 MTpd gross.
We sell our share of natural gas production from the Alba field to the LPG plant, the methanol plant and an LNG
plant. The LPG plant is owned by Alba Plant LLC (“Alba Plant”) in which we have a 28% interest accounted for by
the equity method. The methanol plant is owned by Atlantic Methanol Production Company, LLC (“AMPCO”) in
which we have a 45% interest accounted for by the equity method. The methanol plant purchases natural gas from
the Alba field under a contract that runs through 2026. AMPCO subsequently markets the produced methanol to
customers in the US and northwestern Europe. We sell our share of condensate produced in the Alba field and from
the LPG plant under short-term contracts at market-based prices.
8
Our exploration activities in West Africa center around Blocks O and I offshore Equatorial Guinea and the PH-77
license offshore the Republic of Cameroon. We are the technical operator on Blocks O and I (45% and 40% working
interest, respectively) and the operator on the PH-77 license (50% working interest). We drilled seven wells in the
area during 2007 resulting in three new discoveries and three successful appraisal wells:
Benita – The I-1 well, testing the Benita prospect, resulted in a new gas-condensate discovery on Block I.
Benita appraisal – The I-2 appraisal well on Block I encountered crude oil. Testing has been deferred in order to
secure an additional drilling rig that will be capable of further appraisal drilling downdip in the Benita oil column,
which is in deeper water. It is expected that a rig will be available for drilling the additional Benita appraisal well in
the first quarter of 2008.
Yolanda – The I-3 well, testing the Yolanda prospect, resulted in another new gas-condensate discovery on Block I.
I-4 – The I-4 well on Block I was a successful well on trend with the 2005 Belinda discovery on Block O.
Adriana – The O-2 exploration well (the Adriana Southwest prospect) on Block O offshore Equatorial Guinea did
not contain commercial hydrocarbons. The well was plugged and abandoned.
Belinda appraisal – The O-3 appraisal well on Block O successfully extended the Belinda discovery by establishing
significant downdip resources.
YoYo – The YoYo-1 well resulted in a new gas-condensate discovery on the PH-77 license offshore the Republic of
Cameroon. Additional appraisal work is necessary to verify the areal extent of the discovery. There was also a
secondary target, in which commercial hydrocarbons were not found.
In 2008, we plan to have an active exploration and appraisal drilling program for both Blocks I and O as we assess
our options to commercialize our discoveries in the region.
Effective November 2006, the government of Equatorial Guinea enacted a new hydrocarbons law (the “2006
Hydrocarbons Law”) governing petroleum operations in Equatorial Guinea. The governmental agency responsible
for the energy industry was given the authority to renegotiate any contract for the purpose of adapting any terms and
conditions that are inconsistent with the new law. At this time we are uncertain what economic impact this law will
have on our operations in Equatorial Guinea.
North Sea—Operations in the North Sea (the Netherlands, Norway and the UK) comprise another core international
asset, and we have been conducting business there since 1996. We have working interests in 23 licenses with
working interests ranging from 7% to 100%. We are the operator of four blocks, covered by three licenses. The
North Sea accounted for 17% of 2007 consolidated international sales volumes and 8% of international proved
reserves at December 31, 2007. At December 31, 2007, we held 48,230 gross developed acres and 836,625 gross
undeveloped acres.
In January 2007, production began at the non-operated Dumbarton development (30% working interest) in Blocks
15/20a and 15/20b in the UK sector of the North Sea. Dumbarton, a re-development of the Donan field, includes a
subsea tie-back to the GP III, a floating production, storage and offloading vessel in which we own a 30% interest.
We expect to continue the development of Dumbarton in 2008 with phases 2a and 2b. In addition, we will
participate in the development of the Lochranza prospect, which will also consist of a subsea tie-back to the GP III.
Exploration efforts continued in 2007 as we and our partners successfully completed an exploratory appraisal well
on the Flyndre Block (22.5% working interest) in the UK sector of the North Sea. We also participated in a
successful exploration well at Selkirk in Block 22/22b P233 (30.5% working interest), also in the UK sector of the
North Sea.
Mediterranean Sea (Israel)—Operations in Israel accounted for 23% of 2007 consolidated international sales
volumes and 14% of international proved reserves at December 31, 2007. At December 31, 2007, we held 123,552
gross developed acres and 1,183,479 gross undeveloped acres located between 10 and 60 miles offshore Israel in
water depths ranging from 700 feet to 5,500 feet. Our leasehold position in Israel includes one preliminary permit,
two leases and three licenses, and we are the operator.
We have been operating in the Mediterranean Sea, offshore Israel, since 1998, and our 47% working interest in the
Mari-B field is one of our core international assets. The Mari-B field is the first offshore natural gas production
facility in the State of Israel. During 2007, we completed the Mari-B #7, which is designed to produce twice what a
9
normal Mari-B well produces in Israel, or approximately 200 MMcfpd of natural gas. The Mari-B#7 well has
resulted in peak field deliverability of 600 MMcfpd.
Natural gas sales began in 2004 and have been increasing steadily as Israel’s natural gas infrastructure has
developed. In 2007, our gas sales volumes increased 19% over 2006 volumes and 67% over 2005 volumes. During
2007 we completed construction of a permanent onshore receiving terminal in Ashdod for distribution of natural gas
from the Mari-B field to purchasers. Commissioning of the terminal is expected in early 2008. We also began selling
natural gas to a desalinization plant and a paper mill in 2007. Additional natural gas sales in 2008 will depend on the
timing of onshore pipeline construction and plant conversion, which should allow the Israel Electric Corporation
Limited power plants at Gezer and Hagit to consume gas.
Exploration activities continue in Israel. We are in the process of securing a rig and intend to drill one exploration
well testing the Tamar prospect (33% working interest), offshore northern Israel, in 2008.
Ecuador—Operations in Ecuador accounted for 5% of 2007 consolidated international sales volumes and 8% of
international proved reserves at December 31, 2007. The concession covers 12,355 gross developed acres and
851,771 gross undeveloped acres.
We have been operating in Ecuador since 1996. We are currently utilizing the natural gas from the Amistad field
(offshore Ecuador) to generate electricity through a 100%-owned natural gas-fired power plant, located near the city
of Machala. The Machala power plant, which began operating in 2002, is a single cycle generator with a capacity of
130 MW from twin turbines. It is the only natural gas-fired commercial power generator in Ecuador and currently
one of the lowest cost producers of thermal power in the country. The Machala power plant connects to the Amistad
field via a 40-mile pipeline. During 2007, power generation totaled 911,830 MW hours.
Other International—Other international includes China, Argentina and Suriname.
We have been engaged in exploration and development activities in China since 1996 and production began in 2003.
We are operator of the Cheng Dao Xi field (57% working interest), which is located in the shallow water of the
southern Bohai Bay. During 2007, activities consisted primarily of workover projects. China accounted for 5% of
2007 consolidated international sales volumes and 2% of international proved reserves at December 31, 2007. At
December 31, 2007, we held 7,413 gross developed acres and no undeveloped acres.
We continue to work with our Chinese partner (Shengli) to obtain governmental approval of the Supplemental
Development Plan, designed to further develop the Cheng Dao Xi field through additional drilling and facilities
construction.
Our producing properties in Argentina are located in southern Argentina in the El Tordillo field (13% working
interest), which is characterized by secondary recovery crude oil production. During 2007, we participated in the
drilling of 50 gross (6.7 net) development wells. Argentina accounted for 4% of 2007 consolidated international
sales volumes and 2% of international proved reserves at December 31, 2007. At December 31, 2007, we held
113,325 gross developed acres and no undeveloped acres in Argentina.
In December 2007, we entered into an agreement to sell our interest in Argentina for a sales price of $117.5 million,
effective July 1, 2007. We expect the sale, which is subject to regulatory and partner approvals, to close in 2008.
Crude oil reserves for the Argentina properties totaled 7 MMBbls at December 31, 2007.
Suriname, a country located on the northern coast of South America, represents a new exploration area for us. We
have entered into participation agreements on non-operated Block 30 (60% working interest) and on Block 32
(100% working interest), which combined cover approximately 7.7 million gross acres offshore. We expect to
participate in the drilling of one well on the West Tapir prospect on Block 30 in 2008.
10
Sales Volumes, Price and Cost Data—Sales volumes, price and cost data are as follows:
Sales Volumes (1)
Average Sales Price
Production Cost
Average
Natural Gas Crude Oil Natural Gas Crude Oil
Per Bbl (2)
Per Mcf (2)
MBbls
MMcf
Per BOE (3)
Year Ended December 31, 2007
United States
West Africa (4) (5)
North Sea
Israel
Other International (6)
Total Consolidated Operations
Equity Investee (7)
Total
Year Ended December 31, 2006
United States
West Africa (4) (5)
North Sea
Israel
Other International (6)
Total Consolidated Operations
Equity Investee (7)
Total
Year Ended December 31, 2005
United States
West Africa (4) (5)
North Sea
Israel
Other International (6)
Total Consolidated Operations
Equity Investee (7)
Total
150,457
15,451
$
7.51
$
53.22
$
8.49
48,349
2,276
40,449
9,385
250,916
-
250,916
5,500
4,564
-
2,436
27,951
2,805
30,756
0.29
6.54
2.79
-
5.26
71.27
76.47
-
53.69
60.61
-
5.26
$
55.09
60.10
$
2.89
9.81
1.14
12.06
6.99
164,875
16,715
$
6.61
$
50.68
$
8.12
16,579
2,967
33,906
9,041
227,368
-
227,368
6,519
1,357
-
2,752
27,343
2,931
30,274
0.37
8.00
2.72
0.96
5.55
62.51
67.43
-
52.05
54.47
-
5.55
$
45.83
53.64
$
2.86
10.08
1.60
9.74
6.97
125,543
9,468
$
7.43
$
46.67
$
7.39
23,938
3,394
24,228
8,389
185,492
-
185,492
6,492
1,964
-
2,866
20,790
1,183
21,973
0.25
5.93
2.68
1.10
5.78
42.51
52.68
-
42.37
45.35
-
5.78
$
43.43
45.25
$
2.93
7.54
2.11
7.15
6.06
(1) 2007 volumes include the effect of crude oil sales less than volumes produced of 165 MBbls in Equatorial
Guinea, 112 MBbls in the North Sea and 48 MBbls in other international. 2006 volumes include the effect of
crude oil sales in excess of volumes produced of 195 MBbls in Equatorial Guinea, less than volumes produced
of 99 MBbls in the North Sea, and in excess of volumes produced of 18 MBbls in other international. The
variance between production from the field and sales volumes is attributable to the timing of liquid
hydrocarbon tanker liftings. Sales volumes equal production volumes in 2005.
(2) Average natural gas sales prices in the US reflect an increase of $1.12 per Mcf (2007), and reductions of $0.25
per Mcf (2006) and $0.77 per Mcf (2005) from hedging activities. Average crude oil sales prices for the US
reflect reductions of $13.68 per Bbl (2007), $11.41 per Bbl (2006) and $8.03 per Bbl (2005) from hedging
activities. Average crude oil sales prices for West Africa reflect reductions of $2.19 (2007) and $9.93 (2005)
from hedging activities. We did not hedge West Africa crude oil sales in 2006.
(3) Average production costs include oil and gas operating costs, workover and repair expense, production and ad
valorem taxes, and transportation expense.
(4) Natural gas from the Alba field in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol
plant, an LPG plant and an LNG facility. Sales to these plants are based on a BTU equivalent and then
converted to a dry gas equivalent volume. The methanol and LPG plants are owned by affiliated entities
11
accounted for under the equity method of accounting. The volumes produced by the LPG plant are included in
the crude oil information. For 2007 and 2006, the price on an Mcf basis has been adjusted to reflect the Btu
content of gas sales.
(5) Equatorial Guinea natural gas volumes include sales to the LNG facility of 78,090 Mcfpd for 2007. There were
no natural gas sales to the LNG facility before 2007.
(6) Other International natural gas volumes include Ecuador and Argentina. Although Ecuador natural gas volumes
are included in Other International production, they are excluded from average natural gas sales prices. We
own 100% of the natural gas-to-power project in Ecuador and intercompany natural gas sales are eliminated.
Natural gas production volumes associated with the gas-to-power project were 9,385 MMcf for 2007, 8,933
MMcf for 2006 and 8,321 MMcf for 2005. Other International oil includes China and Argentina.
(7) Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea. LPG volumes were
2,135 MBbls in 2007, 2,297 MBbls in 2006 and 850 MBbls in 2005.
Revenues from sales of crude oil and natural gas and from gathering, marketing and processing have accounted for
90% or more of consolidated revenues for each of the last three fiscal years.
At December 31, 2007, our operated properties accounted for approximately 62% of our total production. Being the
operator of a property improves our ability to directly influence production levels and the timing of projects, while
also enhancing our control over operating expenses and capital expenditures.
Productive Wells—The number of productive crude oil and natural gas wells in which we held an interest as of
December 31, 2007 is as follows:
United States - Onshore
United States - Offshore
West Africa
North Sea
Israel
Ecuador
China
Argentina
Total
Crude Oil Wells
Net
Gross
Natural Gas Wells
Net
Gross
Total
Gross
Net
7,055
28
1
15
-
-
16
732
7,847
5,997.8
26.1
0.4
2.7
-
-
9.1
95.4
6,131.5
4,609
15
19
7
8
5
-
-
4,663
3,134.5
8.1
7.2
0.7
3.8
5.0
-
-
3,159.3
11,664
43
20
22
8
5
16
732
12,510
9,132.3
34.2
7.6
3.4
3.8
5.0
9.1
95.4
9,290.8
Multiple Completions
8
5.9
14
3.6
22
9.5
Productive wells are producing wells and wells capable of production. A gross well is a well in which a working
interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. A
net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The
number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers
and fractions thereof. One or more completions in the same borehole are counted as one well in this table.
12
Developed and Undeveloped Acreage—Developed and undeveloped acreage (including both leases and
concessions) held at December 31, 2007 was as follows:
United States
Onshore
Offshore
Total United States
Equatorial Guinea
Cameroon
North Sea (1)
Israel
China
Ecuador
Argentina
Suriname
Total International
Total Worldwide (2)
Developed Acreage
Net
Gross
Undeveloped Acreage
Gross
Net
1,308,823
147,945
1,456,768
45,203
-
48,230
123,552
7,413
12,355
113,325
-
350,078
1,806,846
835,445
94,963
930,408
15,727
-
5,671
58,142
4,225
12,355
15,548
-
111,668
1,042,076
1,234,858
485,258
1,720,116
850,197
1,125,000
836,625
1,183,479
-
851,771
-
7,740,328
12,587,400
14,307,516
786,391
227,627
1,014,018
379,026
562,500
339,151
532,818
-
851,771
-
6,362,884
9,028,150
10,042,168
(1) The North Sea includes acreage in the UK, the Netherlands and Norway. In 2008, we entered into an
agreement, subject to regulatory approval, to sell our interest in the Norway acreage consisting of 411,065
gross (126,607 net) undeveloped acres.
If production is not established, approximately 731,079 gross acres (433,236 net acres) will expire during 2008,
424,734 gross acres (193,554 net acres) will expire during 2009, and 683,274 gross acres (367,949 net acres)
will expire during 2010.
(2)
Developed acreage includes leases that contain wells capable of production. A gross acre is an acre in which a
working interest is owned. A net acre is deemed to exist when the sum of fractional ownership working interests in
gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres
expressed as whole numbers and fractions thereof. Undeveloped acreage is considered to be those leased acres on
which wells have not been drilled or completed to a point that would permit the production of commercial quantities
of crude oil and natural gas regardless of whether or not such acreage contains proved reserves.
13
Drilling Activity—The results of crude oil and natural gas wells drilled and completed for each of the last three
years were as follows:
Net Exploratory Wells
Net Development Wells
Productive
Dry
Total
Productive (1)
Dry
Total
Year Ended December 31, 2007
United States
West Africa
North Sea
Israel
Argentina
Total
Year Ended December 31, 2006
United States
West Africa
North Sea
Argentina
Total
Year Ended December 31, 2005
United States
West Africa
North Sea
Argentina
Total
14.2
2.6
0.5
-
-
17.3
6.3
-
-
-
6.3
4.7
-
-
-
4.7
4.5
0.5
-
-
0.1
5.1
9.0
0.4
-
-
9.4
10.7
-
0.2
-
10.9
18.7
3.1
0.5
-
0.1
22.4
15.3
0.4
-
-
15.7
15.4
-
0.2
-
15.6
757.6
-
-
0.4
6.7
764.7
666.6
1.8
1.1
7.6
677.1
488.1
0.3
-
7.7
496.1
27.6
-
-
-
-
27.6
5.5
-
-
-
5.5
25.9
-
-
-
25.9
785.2
-
-
0.4
6.7
792.3
672.1
1.8
1.1
7.6
682.6
514.0
0.3
-
7.7
522.0
(1) Does not include wells drilled but not yet completed.
A productive well is an exploratory or a development well that is not a dry well. A dry well (hole) is an exploratory
or a development well found to be incapable of producing either oil or gas in sufficient quantities to justify
completion as an oil or gas well.
An exploratory well is a well drilled to find and produce crude oil or natural gas in an unproved area, to find a new
reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a
known reservoir. A development well, for purposes of the table above and as defined in the rules and regulations of
the SEC, is a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic
horizon known to be productive. The number of wells drilled refers to the number of wells completed at any time
during the respective year, regardless of when drilling was initiated. Completion refers to the installation of
permanent equipment for the production of crude oil or natural gas, or in the case of a dry hole, to the reporting of
abandonment to the appropriate agency.
In addition to the wells drilled and completed during 2007 included in the table above, at December 31, 2007, we
were drilling or completing 2 gross (1.0 net) development wells offshore US, 223 gross (192.3 net) development
wells and 4 gross (3.3 net) exploratory wells onshore US and one gross (0.1 net) development well in Argentina.
Marketing Activities—We seek opportunities to enhance the value of our US natural gas production by marketing
directly to end-users and aggregating natural gas to be sold to natural gas marketers and pipelines. We also engage
in the purchase and sale of third-party crude oil and natural gas production. Such third-party production may be
purchased from non-operators who own working interests in our wells or from other producers’ properties in which
we own no interest.
Natural gas produced in the US is sold predominately under short-term or long-term contracts at market-based
prices. In Equatorial Guinea and Israel, we sell natural gas to end-users under long-term contracts at negotiated
prices. During 2007, approximately 12% of natural gas sales were made pursuant to long-term contracts.
Crude oil and condensate produced in the US and foreign locations is generally sold under short-term contracts at
market-based prices adjusted for location and quality. In China, we sell crude oil into the local market under a long-
term contract at market-based prices. Crude oil and condensate are distributed through pipelines and by trucks or
tankers to gatherers, transportation companies and refineries.
14
Significant Purchaser—Marathon Petroleum Supply Company (“Marathon”) was the largest single non-affiliated
purchaser of 2007 production and purchased our share of condensate from the Alba field in Equatorial Guinea. Sales
to Marathon accounted for 18% of 2007 crude oil sales, or 10% of 2007 total oil and gas sales. No other single non-
affiliated purchaser accounted for 10% or more of crude oil and natural gas sales in 2007. We believe that the loss of
any one purchaser would not have a material effect on our financial position or results of operations since there are
numerous potential purchasers of our production.
Hedging Activities—Commodity prices remained volatile during 2007 and prices for crude oil and natural gas are
affected by a variety of factors beyond our control. We have used derivative instruments, and expect to do so in the
future, to achieve a more predictable cash flow by reducing our exposure to commodity price fluctuations. For
additional information, see Item 1A. Risk Factors—Hedging transactions may limit our potential gains, Item 7A.
Quantitative and Qualitative Disclosures About Market Risk, and Item 8. Financial Statements and Supplementary
Data—Note 12—Derivative Instruments and Hedging Activities.
Regulations
Government Regulation—Exploration for, and production and sale of, crude oil and natural gas are extensively
regulated at the international, federal, state and local levels. Crude oil and natural gas development and production
activities are subject to various laws and regulations (and orders of regulatory bodies pursuant thereto) governing a
wide variety of matters, including, among others, allowable rates of production, prevention of waste and pollution
and protection of the environment. Laws affecting the crude oil and natural gas industry are under constant review
for amendment or expansion and frequently increase the regulatory burden on companies. Our ability to
economically produce and sell crude oil and natural gas is affected by a number of legal and regulatory factors,
including federal, state and local laws and regulations in the US and laws and regulations of foreign nations. Many
of these governmental bodies have issued rules and regulations that are often difficult and costly to comply with, and
that carry substantial penalties for failure to comply. These laws, regulations and orders may restrict the rate of
crude oil and natural gas production below the rate that would otherwise exist in the absence of such laws,
regulations and orders. The regulatory burden on the crude oil and natural gas industry increases our costs of doing
business and consequently affects our profitability.
Environmental Matters—As a developer, owner and operator of crude oil and natural gas properties, we are subject
to various federal, state, local and foreign country laws and regulations relating to the discharge of materials into,
and the protection of, the environment. We must take into account the cost of complying with environmental
regulations in planning, designing, drilling, operating and abandoning wells. In most instances, the regulatory
requirements relate to the handling and disposal of drilling and production waste products, water and air pollution
control procedures, and the remediation of petroleum-product contamination. Under state and federal laws, we could
be required to remove or remediate previously disposed wastes, including wastes disposed of or released by us or
prior owners or operators in accordance with current laws or otherwise, to suspend or cease operations in
contaminated areas, or to perform remedial well plugging operations or cleanups to prevent future contamination.
The US Environmental Protection Agency and various state agencies have limited the disposal options for hazardous
and non-hazardous wastes. The owner and operator of a site, and persons that treated, disposed of or arranged for the
disposal of hazardous substances found at a site, may be liable, without regard to fault or the legality of the original
conduct, for the release of a hazardous substance into the environment. The US Environmental Protection Agency,
state environmental agencies and, in some cases, third parties are authorized to take actions in response to threats to
human health or the environment and to seek to recover from responsible classes of persons the costs of such action.
Furthermore, certain wastes generated by our crude oil and natural gas operations that are currently exempt from
treatment as hazardous wastes may in the future be designated as hazardous wastes and, therefore, be subject to
considerably more rigorous and costly operating and disposal requirements. See Item 1A. Risk Factors—We are
subject to various governmental regulations and environmental risks that may cause us to incur substantial costs.
Federal and state occupational safety and health laws require us to organize information about hazardous materials
used, released or produced in our operations. Certain portions of this information must be provided to employees,
state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set
forth in federal workplace standards.
Certain state or local laws or regulations and common law may impose liabilities in addition to, or restrictions more
stringent than, those described herein.
15
We have made and will continue to make expenditures in our efforts to comply with environmental requirements.
We do not believe that we have, to date, expended material amounts in connection with such activities or that
compliance with such requirements will have a material adverse effect upon our capital expenditures, earnings or
competitive position. Although such requirements do have a substantial impact upon the crude oil and natural gas
industry, they do not appear to affect us to any greater or lesser extent than other companies in the industry.
Competition
The crude oil and natural gas industry is highly competitive. We encounter competition from other crude oil and
natural gas companies in all areas of operations, including the acquisition of seismic and lease rights on crude oil
and natural gas properties and for the labor and equipment required for exploration and development of those
properties. Our competitors include major integrated crude oil and natural gas companies and numerous independent
crude oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are
large, well established companies. Such companies may be able to pay more for seismic and lease rights on crude oil
and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number
of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties
and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties
and to consummate transactions in a highly competitive environment. See Item 1A. Risk Factors—We face
significant competition and many of our competitors have resources in excess of our available resources.
Geographical Data
We have operations throughout the world and manage our operations by country. Information is grouped into five
components that are all primarily in the business of crude oil and natural gas acquisition, exploration, development
and production: United States, West Africa, North Sea, Israel, and Other International, Corporate and Marketing.
For more information, see Item 8. Financial Statements and Supplementary Data—Note 15—Segment Information.
Employees
Our total number of employees increased during the year from 1,243 at December 31, 2006 to 1,398 at
December 31, 2007. The 2007 year-end employee count includes 181 foreign nationals working as employees in
Ecuador, China, Israel, the UK, Equatorial Guinea, Cameroon and Suriname.
Offices
Our principal corporate office, including our offices for US and international operations, is located at 100
Glenborough Drive, Suite 100, Houston, Texas 77067-3610. We maintain additional offices in Ardmore, Oklahoma
and Denver, Colorado and in China, Cameroon, Ecuador, Equatorial Guinea, Israel, Suriname and the UK.
Title to Properties
We believe that our title to the various interests set forth above is satisfactory and consistent with generally accepted
industry standards, subject to exceptions that are not so material as to detract substantially from the value of the
interests or materially interfere with their use in our operations. Individual properties may be subject to burdens such
as royalty, overriding royalty and other outstanding interests customary in the industry. In addition, interests may be
subject to obligations or duties under applicable laws or burdens such as production payments, net profits interest,
liens incident to operating agreements and for current taxes, development obligations under crude oil and natural gas
leases or capital commitments under production sharing contracts or exploration licenses.
Available Information
Our website address is www.nobleenergyinc.com. Available on this website under “Investor Relations—Investor
Relations Menu—SEC Filings,” free of charge, are our annual reports on Form 10-K, quarterly reports on
Form 10-Q, current reports on Form 8-K, Forms 3, 4 and 5 filed on behalf of directors and officers and amendments
to those reports as soon as reasonably practicable after such materials are electronically filed with or furnished to the
SEC.
Also posted on our website, and available in print upon request made by any stockholder to the Investor Relations
Department, are charters for our Audit Committee; Compensation, Benefits and Stock Option Committee; Corporate
Governance and Nominating Committee; and Environment, Health and Safety Committee. Copies of the Code of
Business Conduct and Ethics, and the Code of Ethics for Chief Executive and Senior Financial Officers (the
“Codes”) are posted on our website under the “Corporate Governance” section. Within the time period required by
16
the SEC and the NYSE, as applicable, we will post on our website any modifications to the Codes and any waivers
applicable to senior officers as defined in the applicable Code, as required by the Sarbanes-Oxley Act of 2002.
In 2007, we submitted the annual certification of our Chief Executive Officer regarding compliance with the
NYSE’s corporate governance listing standards, pursuant to Section 303A.12(a) of the NYSE Listed Company
Manual.
Item 1A. Risk Factors.
Crude oil and natural gas prices are volatile and a substantial reduction in these prices could adversely affect our
results and the price of our common stock.
Our revenues, operating results and future rate of growth depend highly upon the prices we receive for our crude oil
and natural gas production. Historically, the markets for crude oil and natural gas have been volatile and are likely to
continue to be volatile in the future. The markets and prices for crude oil and natural gas depend on factors beyond
our control. These factors include demand for crude oil and natural gas, which fluctuates with changes in market and
economic conditions, and other factors, including:
• 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 producing 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.
Significant declines in crude oil and natural gas prices for an extended period may have the following effects on our
business:
• 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 flow;
• reducing the carrying value of our crude oil and natural gas properties; or
• limiting our access to sources of capital, such as equity and long-term debt.
Estimates of crude oil and natural gas reserves are not precise.
There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their value, including
many factors that are beyond our control. Reservoir engineering is a subjective process of estimating underground
accumulations of crude oil and natural gas that cannot be measured in an exact manner. Our reserve estimates are
based on year-end commodity prices; therefore, reserve quantities will change when actual prices increase or
decrease. The estimates depend on a number of factors and assumptions that may vary considerably from actual
results, including:
• historical production from the area compared with production from other areas;
• the assumed effects of regulations by governmental agencies;
• assumptions concerning future crude oil and natural gas prices;
• future operating costs;
• severance and excise taxes;
• development costs; and
• workover and remedial costs.
17
For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to
any particular group of properties, classifications of those reserves based on risk of recovery and estimates of the
future net cash flows expected from them prepared by different engineers or by the same engineers but at different
times may vary substantially. Accordingly, reserve estimates may be subject to upward or downward adjustment,
and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially,
from estimates.
Additionally, because some of our reserve estimates are calculated using volumetric analysis, those estimates are
less reliable than the estimates based on a lengthy production history. Volumetric analysis involves estimating the
volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the
structure. In addition, realization or recognition of proved undeveloped reserves will depend on our development
schedule and plans. A change in future development plans for proved undeveloped reserves could cause the
discontinuation of the classification of these reserves as proved.
Failure to fund continued capital expenditures could adversely affect our properties.
Our acquisition, exploration, and development activities require substantial capital expenditures. Historically, we
have funded our capital expenditures through a combination of cash flows from operations, our revolving bank
credit facility and debt and equity issuances. Future cash flows are subject to a number of variables, such as the level
of production from existing wells, prices of crude oil and natural gas, and our success in finding, developing and
producing new reserves. If revenue were to decrease as a result of lower crude oil and natural gas prices or
decreased production, and our access to capital were limited, we would have a reduced ability to replace our
reserves, resulting in a decrease in production over time. If our cash flow from operations is not sufficient to meet
our obligations and fund our capital budget, we may not be able to access debt, equity or other methods of financing
on an economic basis to meet these requirements. If we are not able to fund our capital expenditures, interests in
some properties might be reduced or forfeited as a result.
A recession or an economic slowdown could have a material adverse impact on our financial position, results of
operations and cash flows.
The oil and gas industry is cyclical in nature and tends to reflect general economic conditions. Currently, the US
economy is slowing and may be headed toward a recession. A recession may lead to significant fluctuations in
demand and pricing for our crude oil and natural gas production. If we were to continue development of our
property interests after a decline in the prices of crude oil and natural gas had occurred, our profitability may be
significantly affected by decreased demand and lower commodity prices. In addition, our future access to capital
could be limited due to tightening credit markets.
Our international operations may be adversely affected by economic and political developments.
We have significant international crude oil and natural gas operations. These operations may be adversely affected
by political and economic developments, including the following:
• war, terrorist acts and civil disturbances;
• loss of revenue, property and equipment as a result of actions taken by foreign crude oil and natural gas
producing nations, such as expropriation or nationalization of assets and renegotiation, modification or
nullification of existing contracts, such as may occur pursuant to the hydrocarbons law enacted in 2006 by
the government of Equatorial Guinea;
• changes in taxation policies;
• laws and policies of the US and foreign jurisdictions affecting foreign investment, taxation, trade and
business conduct;
• foreign exchange restrictions;
• international monetary fluctuations and changes in the value of the US dollar; and
• other hazards arising out of foreign governmental sovereignty over areas in which we conduct operations.
Exploration, development and production risks and natural disasters could result in liability exposure or the loss
of production and revenues.
Our operations are subject to hazards and risks inherent in the drilling, production and transportation of crude oil and
natural gas, including:
• pipeline ruptures and spills;
18
• fires;
• explosions, blowouts and cratering;
• formations with abnormal pressures;
• equipment malfunctions;
• hurricanes; and
• other natural disasters.
Any of these can result in loss of hydrocarbons, environmental pollution and other damage to our properties or the
properties of others.
Exploration and development drilling may not result in commercially productive reserves.
We do not always encounter commercially productive reservoirs through our drilling operations. The wells we drill
or participate in may not be productive and we may not recover all or any portion of our investment in those wells.
The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that
crude oil or natural gas is present or may be produced economically. The cost of drilling, completing and operating a
well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be
unprofitable if we drill dry holes or wells that are productive but do not produce enough reserves to return a profit
after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled as a
result of a variety of factors, including:
• 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.
We may be unable to make attractive acquisitions or integrate acquired businesses and/or assets, and any
inability to do so may disrupt our business.
One aspect of our business strategy calls for acquisitions of businesses and assets that complement or expand our
current business. We cannot provide assurance that we will be able to identify attractive acquisition opportunities.
Even if we do identify attractive opportunities, we cannot provide assurance that we will be able to complete the
acquisition of them or do so on commercially acceptable terms. Additionally, if we acquire another business, we
could have difficulty integrating its operations, systems, management and other personnel and technology with our
own. These difficulties could disrupt ongoing business, distract management and employees, increase expenses and
adversely affect results of operations. Even if these difficulties could be overcome, we cannot provide assurance that
the anticipated benefits of any acquisition would be realized.
We are subject to various governmental regulations and environmental risks that may cause us to incur
substantial costs.
From time to time, in varying degrees, political developments and federal and state laws and regulations affect our
operations. In particular, price controls, taxes and other laws relating to the crude oil and natural gas industry,
changes in these laws and changes in administrative regulations have affected and in the future could affect crude oil
and natural gas production, operations and economics. We cannot predict how agencies or courts will interpret
existing laws and regulations or the effect these adoptions and interpretations may have on our business or financial
condition.
Our business is subject to laws and regulations promulgated by international, federal, state and local authorities
relating to the exploration for, and the development, production and marketing of, crude oil and natural gas, as well
as safety matters. Legal requirements are frequently changed and subject to interpretation and we are unable to
predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be
required to make significant expenditures to comply with governmental laws and regulations.
Our operations are subject to complex international, federal, state and local environmental laws and regulations
including in the case of federal laws, the Comprehensive Environmental Response, Compensation and Liability Act,
as amended, the Resource Conservation and Recovery Act, as amended, the Oil Pollution Act of 1990, the Clean Air
Act, and the Clean Water Act. Environmental laws and regulations change frequently and the implementation of
19
new, or the modification of existing, laws or regulations could negatively impact our operations. The discharge of
natural gas, crude oil, or other pollutants into the air, soil or water may give rise to significant liabilities on our part
to the government and third parties and may require us to incur substantial costs of remediation.
Potential regulations regarding climate change could alter the way we conduct our business.
As awareness of climate change issues increases, governments around the world are beginning to address the issue.
This may result in new environmental regulations that may unfavorably impact us, our suppliers, and our customers.
The cost of meeting these requirements may have an adverse impact on our financial condition, results of operations
and cash flows.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel and other oil field services could
adversely affect our ability to execute our exploration and development plans on a timely basis and within our
budget.
Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified
personnel. During these periods, the costs of rigs, equipment and supplies are substantially greater and their
availability may be limited. As a result of increasing levels of exploration and production in response to strong
demand for crude oil and natural gas, the demand for oilfield services and the costs of these services have increased.
Additionally, these services may not be available on commercially reasonable terms.
We may not have enough insurance to cover all of the risks we face, which could result in significant financial
exposure.
Exploration for and production of crude oil and natural gas can be hazardous, involving natural disasters and other
unfortuitous events such as blowouts, cratering, fire and explosion and loss of well control which can result in
damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property and
the environment. In accordance with industry practices, we maintain insurance against many, but not all, potential
perils confronting our operations and in coverage amounts and deductible levels that we believe to be prudent.
Consistent with that profile, our insurance program is structured to provide us financial protection from unfavorable
loss severity resulting from damages to or the loss of physical assets or loss of human life, liability claims of third
parties, and business interruption (loss of production) attributed to certain assets. Although we believe the coverages
and amounts of insurance carried are adequate, we may not have sufficient protection against some of the risks we
face, because we chose not to insure certain risks, insurance is not available on commercially reasonable terms or
actual losses exceed coverage limits. If an event occurs that is not covered by insurance or not fully protected by
insured limits, it could have an adverse impact on our financial condition, results of operations and cash flows.
We face significant competition and many of our competitors have resources in excess of our available resources.
We operate in the highly competitive areas of crude oil and natural gas exploration, exploitation, acquisition and
production. We face intense competition from a large number of independent, technology-driven companies as well
as both major and other independent crude oil and natural gas companies in a number of areas such as:
• seeking to acquire desirable producing properties or new leases for future exploration;
• marketing our crude oil and natural gas production;
• seeking to acquire the equipment and expertise necessary to operate and develop properties; and
• attracting and retaining employees with certain skills.
Many of our competitors have financial and other resources substantially in excess of those available to us. This
highly competitive environment could have an adverse impact on our business.
Our level of indebtedness may limit our financial flexibility.
As of December 31, 2007, we had long-term indebtedness of $1.9 billion (excluding unamortized discount), with
$1.2 billion drawn under our bank credit facility. Our indebtedness represented 28% of our total book capitalization
at December 31, 2007.
Our level of indebtedness affects our operations in several ways, including the following:
• 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;
20
• 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;
• 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.
We may incur additional debt in order to fund our acquisition, exploration and development activities. A higher
level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt
obligations and reduce our level of indebtedness depends on future performance. General economic conditions,
crude oil and natural gas prices and financial, business and other factors will affect our operations and our future
performance. Many of these factors are beyond our control and we may not be able to generate sufficient cash flow
to pay the interest on our debt, and future working capital, borrowings and equity financing may not be available to
pay or refinance such debt.
Hedging transactions may limit our potential gains.
In order to manage our exposure to price risks in the marketing of our crude oil and natural gas, we enter into crude
oil and natural gas price hedging arrangements with respect to a portion of our expected production. Our hedges,
consisting of a series of contracts, are limited in duration, usually for periods of one to four years. While intended to
reduce the effects of volatile crude oil and natural gas prices, such transactions may limit our potential gains if crude
oil and natural gas prices rise over the price established by the arrangements. In trying to manage our exposure to
price risk, we may end up hedging too much or too little, depending upon how our crude oil or natural gas volumes
and our production mix fluctuate in the future. In addition, hedging transactions may expose us to the risk of
financial loss in certain circumstances, including instances in which our production is less than expected; there is a
widening of price basis differentials between delivery points for our production and the delivery point assumed in
the hedge arrangement; the counterparties to our future contracts fail to perform under the contracts; or a sudden
unexpected event materially impacts crude oil or natural gas prices. We cannot assure that our hedging transactions
will reduce the risk or minimize the effect of any decline in crude oil or natural gas prices.
Information technology systems implementation issues could disrupt our internal operations, increase our costs
and adversely affect our financial results or our ability to report our financial results.
We are currently in the process of implementing a new Enterprise Resource Planning software system to replace our
various legacy systems. Our implementation is based on a phased approach, the first phase of which was
implemented fourth quarter 2007. We expect to implement additional phases during 2008. As a part of this effort,
we are transitioning data and changing processes and this may be more expensive, time consuming and resource
intensive than planned. Any disruptions that may occur in the implementation or operation of this system or any
future systems could increase our expenses and adversely affect our ability to report in an accurate and timely
manner our financial position, results of operations and cash flows and to otherwise operate our business.
Provisions in our Certificate of Incorporation and Delaware law may inhibit a takeover of us.
Under our Certificate of Incorporation, our Board of Directors is authorized to issue shares of our common or
preferred stock without approval of our stockholders. Issuance of these shares could make it more difficult to
acquire us without the approval of our Board of Directors as more shares would have to be acquired to gain control.
In addition, Delaware law imposes restrictions on mergers and other business combinations between us and any
holder of 15% or more of our outstanding common stock. These provisions may deter hostile takeover attempts that
could result in an acquisition of us that would have been financially beneficial to our stockholders.
Disclosure Regarding Forward-Looking Statements
This annual report on Form 10-K and the documents incorporated by reference in this report contain forward-
looking statements within the meaning of the federal securities laws. Forward-looking statements give our current
expectations or forecasts of future events. These forward-looking statements include, among others, the following:
• our growth strategies;
• our ability to successfully and economically explore for and develop crude oil and natural gas resources;
21
• anticipated trends in our business;
• our future results of operations;
• our liquidity and ability to finance our acquisition, exploration and development activities;
• market conditions in the oil and gas industry;
• our ability to make and integrate acquisitions; and
• the impact of governmental regulation.
Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “anticipate,”
“estimate” and similar words, although some forward-looking statements may be expressed differently. These
forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions
and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We
caution that forward-looking statements are not guarantees and that actual results could differ materially from those
expressed or implied in the forward-looking statements. You should consider carefully the statements under Item
1A. Risk Factors and other sections of this report, which describe factors that could cause our actual results to differ
from those set forth in the forward-looking statements.
Item 1B. Unresolved Staff Comments.
None.
Item 3.
Legal Proceedings.
We are among a group of eighteen defendants named in a lawsuit filed August 23, 2002 by Dore Energy
Corporation under Docket Number 10-16202 in the 38th Judicial District Court, Cameron Parish, Louisiana. The
lawsuit alleges damage to property owned by Dore resulting from oil and gas activities dating to the 1930’s. Our
predecessor, Samedan Oil Corporation, operated on a portion of the property from 1989 to 1999. Dore has delivered
documents alleging approximately $140 million in damages. Trial is currently set for April 14, 2008. We intend to
vigorously defend against these allegations and believe that our share of damages, if any, will not have a material
adverse effect on our results of operations, financial condition or liquidity.
The Illinois Environmental Protection Agency (“IEPA”) issued a notice of violation to Equinox Oil Company on
September 25, 2001 alleging violation of air emission and permitting regulations for a facility known as the Zif Gas
Plant located near Clay City, Illinois. On January 17, 2007, the IEPA re-issued written notices of these alleged
violations in the name of Equinox’s successors in interest, and our wholly-owned subsidiaries, Elysium Energy,
LLC and Noble Energy Production, Inc. On March 16, 2007, the IEPA accepted our compliance commitment
agreement wherein we agreed to pay a delayed permit fee, install an incineration/caustic scrubber emissions control
system at the site, and fund a supplemental environmental project (“SEP”) in the nearby community. At this time,
we expect no additional monies to be expended other than these amounts for which we have fully accrued. As of
December 31, 2007, this matter has been concluded.
We are involved in various legal proceedings, including the foregoing matters, in the ordinary course of business.
These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously
in all such matters and we do not believe that the ultimate disposition of such proceedings will have a material
adverse effect on our consolidated financial position, results of operations or cash flows.
Item 4.
Submission of Matters to a Vote of Security Holders.
There were no matters submitted to a vote of security holders during the fourth quarter of 2007.
22
Executive Officers
The following table sets forth certain information, as of February 25, 2008, with respect to our executive officers.
Name
Age
Position
Charles D. Davidson (1)
57
Chairman of the Board, President, Chief Executive Officer and
Director
David L. Stover (2)
Chris Tong (3)
50
Executive Vice President, Chief Operating Officer
51
Senior Vice President, Chief Financial Officer
Alan R. Bullington (4)
56
Senior Vice President, International
Susan M. Cunningham (5)
52
Senior Vice President, Exploration
Arnold J. Johnson (6)
Andrea Lee Robison (7)
52
Vice President, General Counsel and Secretary
49
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 on
August 1, 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 on
January 1, 2005. Prior to January 1, 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) Alan R. Bullington was elected a Vice President of Noble Energy on April 24, 2001 and a Senior Vice
President of Noble Energy on July 27, 2004 and is currently responsible for Noble Energy’s International
Division. Prior thereto, he served as Vice President and General Manager, International Division of Samedan
Oil Corporation beginning January 1, 1998. Prior thereto, he served as Manager-International Operations and
Exploration and as Manager-International Operations. Prior to his employment with Samedan in 1990, he held
various management positions within the exploration and production division of Texas Eastern Transmission
Company.
(5) 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
23
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.
(6) Arnold J. Johnson was elected Vice President, General Counsel and Secretary of Noble Energy on
February 1, 2004. Prior thereto, 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.
(7) Andrea Lee Robison was elected to the position of Vice President of Noble Energy on November 1, 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.
24
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities.
Common Stock. Our common stock, $3.33 1/3 par value, is listed and traded on the NYSE under the symbol
“NBL.” The declaration and payment of dividends are at the discretion of our Board of Directors and the amount
thereof will depend on our results of operations, financial condition, contractual restrictions, cash requirements,
future prospects and other factors deemed relevant by the Board of Directors.
Stock Prices and Dividends by Quarters. The high and low sales price per share of common stock on the NYSE and
quarterly dividends paid per share were as follows:
2006
First quarter
Second quarter
Third quarter
Fourth quarter
2007
First quarter
Second quarter
Third quarter
Fourth quarter
High
Low
$
46.91
49.33
51.71
54.64
$
60.69
65.50
70.55
81.64
$
38.32
36.14
41.80
41.77
$
46.33
58.81
58.17
69.69
Dividends
Per Share
$
0.050
0.075
0.075
0.075
$
0.075
0.120
0.120
0.120
On January 22, 2008, the Board of Directors declared a quarterly cash dividend of 12.0 cents per common share,
which was paid February 19, 2008 to shareholders of record on February 4, 2008.
Transfer Agent and Registrar. The transfer agent and registrar for the common stock is Wells Fargo Bank, N.A., 161
North Concord Exchange, South St. Paul, MN, 55075.
Stockholders’ Profile. Pursuant to the records of the transfer agent, as of February 12, 2008, the number of holders
of record of common stock was 817.
Stock Repurchases. We did not repurchase any of our common stock during the fourth quarter of 2007.
Equity Compensation Plan Information. The following table summarizes information regarding the number of
shares of our common stock that are available for issuance under all of our existing equity compensation plans as of
December 31, 2007.
Number of securities
to be issued upon
exercise of
outstanding options
(a)
Weighted-average
exercise price of
outstanding
options, warrants
and rights
(b)
6,175,061
$
32.98
-
6,175,061
-
32.98
$
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column (a))
(c)
6,713,971
-
6,713,971
Plan Category
Equity compensation plans
approved by security holders
Equity compensation plans not
approved by security holders
Total
Stock Performance Graph. This graph shows our cumulative total shareholder return over the five-year period from
December 31, 2002, to December 31, 2007. The graph also shows the cumulative total returns for the same five-year
period of the S&P 500 Index, an old peer group of companies and a new peer group of companies. The companies in
25
the old peer group, which has been adjusted for the effects of industry consolidation, consist of Anadarko Petroleum
Corp., Apache Corp., Chesapeake Energy Corp., Devon Energy Corp., EOG Resources, Inc., Forest Oil Corp.,
Murphy Oil Corp., Newfield Exploration Company, Pioneer Natural Resources Company, Stone Energy Corp., and
XTO Energy Inc. The companies in the new peer group consist of Anadarko Petroleum Corp., Apache Corp., Cabot
Oil & Gas Corp., Chesapeake Energy Corp., Devon Energy Corp., EOG Resources, Inc., Forest Oil Corp., Murphy
Oil Corp., Newfield Exploration Company, Pioneer Natural Resources Company, Plains Exploration and Production
Company, Range Resources Corp., Southwestern Energy Company, and XTO Energy Inc. The changes in peer
group were made as a result of industry consolidation and pursuant to a resolution adopted by the Compensation,
Benefits and Stock Option Committee of the Board of Directors. The comparison assumes $100 was invested on
December 31, 2002, in our common stock, in the S&P 500 Index and in our old and new peer groups and assumes
that all of the dividends were reinvested.
COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Noble Energy, Inc., The S&P 500 Index,
A New Peer Group And An Old Peer Group
$500
$450
$400
$350
$300
$250
$200
$150
$100
$50
$0
12/02
12/03
12/04
12/05
12/06
12/07
Noble Energy, Inc.
S&P 500
New Peer Group
Old Peer Group
* $100 invested on 12/31/02 in stock or index-including reinvestment of dividends. Fiscal year ending December 31.
Copyright © 2008, Standard & Poor's, a division of The McGraw-Hill Companies, Inc. All rights reserved.
www.researchdatagroup.com/S&P.htm
Noble Energy, Inc.
S&P 500
New Peer Group
Old Peer Group
12/02
12/03
12/04
12/05
12/06
12/07
100.00
100.00
100.00
100.00
118.88
128.68
129.82
129.53
165.66
142.69
174.50
170.44
217.40
149.70
278.18
267.61
266.26
173.34
276.86
260.17
434.46
182.87
403.91
375.03
26
Item 6.
Selected Financial Data.
Revenues and Income
Total revenues
Income from continuing operations
Net income
Per Share Data
Basic earnings per share -
Income from continuing operations
Net income
Cash dividends
Year-end stock price
Basic weighted average shares outstanding
Cash Flows
Net cash provided by operating activities
Additions to property, plant and equipment
Acquisitions
Financial Position
Property, plant, and equipment, net
Goodwill
Total assets
Long-term obligations -
Long-term debt
Deferred income taxes
Asset retirement obligations
Derivative instruments
Other deferred credits and
noncurrent liabilities
Shareholders' equity
Operations Information
Natural gas sales (Mcfpd)
Average realized price ($/Mcf) (3)
Crude oil sales (Bopd)
Average realized price ($/Bbl) (3)
Equity investee sales (Bopd)
Average realized price ($/Bbl)
Proved Reserves
Natural gas reserves (Bcf)
Crude oil reserves (MMBbl)
Total reserves (MMBoe)
Number of employees
2007
Year Ended December 31,
2005 (2)
2006 (1)
2004
(in thousands, except share amounts)
2003
$
3,272,030
943,870
943,870
$
2,940,082
678,428
678,428
$
2,186,723
645,720
645,720
$
1,351,051
313,850
328,710
$
1,008,226
89,892
77,992
$
5.52
5.52
0.435
80.66
171,078
$
3.86
3.86
0.275
49.07
175,707
$
4.20
4.20
0.150
40.30
153,773
$
2.69
2.82
0.100
30.83
116,550
$
0.79
0.68
0.085
22.22
113,928
$
2,016,573
1,414,515
-
$
1,730,306
1,357,039
412,257
$
1,239,878
785,610
1,111,099
$
708,186
553,643
-
$
602,770
511,434
-
7,944,464
760,496
10,830,896
1,851,087
1,983,833
130,956
82,803
7,170,757
781,290
9,588,625
1,800,810
1,758,452
127,689
328,875
6,198,916
862,868
8,878,033
2,030,533
1,201,191
278,540
757,509
2,180,715
2,046,909
-
-
3,435,784
2,820,800
880,256
180,415
175,415
9,678
776,021
161,912
101,804
7,400
337,667
4,808,807
274,720
4,113,817
279,971
3,090,144
69,479
1,459,988
72,776
1,073,573
687,444
622,927
508,195
366,965
336,611
$
5.26
76,581
$
5.55
74,915
$
5.78
56,958
$
4.76
44,481
$
4.19
35,101
$
$
$
$
$
60.61
7,684
55.09
54.47
8,032
45.83
45.35
3,240
43.43
34.48
894
32.01
27.67
913
25.47
$
$
$
$
$
3,307
329
880
1,398
3,231
296
835
1,243
3,091
291
806
1,171
1,987
193
525
559
1,642
183
457
583
(1)
(2)
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 3—Acquisitions and Divestitures for additional
information.
Includes effect of Patina Merger. See Item 8. Financial Statements and Supplementary Data—Note 3—
Acquisitions and Divestitures for additional information.
(3) Prices include effects of oil and gas hedging activities. See Item 8. Financial Statements and Supplementary
Data—Note 12—Derivative Instruments and Hedging Activities.
27
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
We are an independent energy company engaged in the acquisition, exploration, development, production and
marketing of crude oil and natural gas domestically and internationally. We operate throughout major basins in the
US including Colorado’s Wattenberg field and Piceance basin, the Mid-continent area of western Oklahoma and the
Texas Panhandle, the San Juan basin in New Mexico, the Gulf Coast and the deepwater Gulf of Mexico. We also
conduct business internationally, in China, Ecuador, the Mediterranean Sea, the North Sea, West Africa (Equatorial
Guinea and Cameroon) and in other areas.
Our accompanying consolidated financial statements, including the notes thereto, contain detailed information that
should be referred to in conjunction with the following discussion.
EXECUTIVE OVERVIEW
We are a worldwide producer of crude oil and natural gas. Our strategy is to achieve growth in earnings and cash
flow through the development of a high quality portfolio of producing assets that is diversified between US and
international projects. The Patina Merger, purchase of U.S. Exploration and sale of Gulf of Mexico shelf properties
have allowed us to achieve a strategic objective of enhancing our US asset portfolio. The result is a company with
assets and capabilities that include growing US basins coupled with a significant portfolio of international
properties. Our reserve base includes both US and international sources at 58% US and 42% international. We are
now a larger, more diversified company with greater opportunities for both US and international growth.
2007 was a strong year for us, both financially and operationally. Significant financial results included the
following:
• net income of $944 million, a 39% increase over 2006 net income;
• diluted earnings per share of $5.45, a 44% increase over 2006;
• cash flow provided by operating activities of $2.0 billion, a 17% increase over 2006; and
• completion of a $500 million common stock repurchase program begun in 2006.
Significant operational highlights included the following:
• eight successful exploration wells drilled internationally, six offshore West Africa and two in the North Sea;
• deepwater Gulf of Mexico exploration success at Isabela (Mississippi Canyon Block 562);
• commencement of production and continued ramp-up at the Dumbarton development and successful
exploratory appraisal well drilled at the Flyndre prospect in the UK sector of the North Sea;
• completion of the Mari-B #7 well and record natural gas sales in Israel;
• continued success of development program in the US Wattenberg field; and
• acquisition of approximately 290,000 net acres onshore US in the Piceance basin, Niobrara trend and New
Albany Shale areas.
Sale of Argentina—In December 2007, we entered into an agreement to sell our interest in Argentina for a sales
price of $117.5 million, effective July 1, 2007. We expect the sale, which is subject to regulatory and partner
approvals, to close in 2008.
Equatorial Guinea 2006 Hydrocarbons Law—Effective November 2006, the government of Equatorial Guinea
enacted the 2006 Hydrocarbons Law governing petroleum operations in Equatorial Guinea. The governmental
agency responsible for the energy industry was given the authority to renegotiate any contract for the purpose of
adapting any terms and conditions that are inconsistent with the new law. At this time we are uncertain what
economic impact this law will have on our operations in Equatorial Guinea.
2008 OUTLOOK
We expect crude oil and natural gas production to increase in 2008 compared to 2007. Factors which may impact
our expected year-over-year increase in production include:
• higher sales of natural gas from the Alba field in Equatorial Guinea; and
• growing production from the D-J and Piceance basins, where we are continuing active drilling programs;
offset by:
• natural field decline in the Gulf Coast area.
28
Factors which may impact our expected production profile include:
• potential hurricane-related volume curtailments in the Gulf of Mexico and Gulf Coast areas;
• potential winter storm-related volume curtailments in the Northern region of our US operations;
• potential pipeline and processing facility capacity constraints in the Rocky Mountain area of our US
operations;
• infrastructure development in Israel;
• potential downtime at the methanol, LPG and/or LNG facilities in Equatorial Guinea;
• seasonal variations in rainfall in Ecuador that affect our natural gas-to-power project; and
• timing of capital expenditures, as discussed below, which are expected to result in near-term production.
2008 Budget—We have budgeted capital expenditures of approximately $1.6 billion for 2008. Approximately 24%
of the 2008 capital budget has been allocated to exploration opportunities and 76% has been allocated to production,
development and other projects. US spending is budgeted for $1.2 billion, international expenditures are budgeted
for $392 million and corporate expenditures are budgeted for $27 million. The 2008 budget does not include the
impact of possible asset purchases. We expect that the 2008 capital budget will be funded primarily from cash flows
from operations and borrowings under our revolving credit facility. We will evaluate the level of capital spending
throughout the year based on drilling results, commodity prices, cash flows from operations and property
acquisitions and divestitures.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of the consolidated financial statements requires our management to make a number of estimates
and assumptions relating to the reported amounts of assets and liabilities and the disclosures of contingent assets and
liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses
during the period. When alternatives exist among various accounting methods, the choice of accounting method can
have a significant impact on reported amounts. The following is a discussion of the accounting policies, estimates
and judgments which management believes are most significant in the application of generally accepted accounting
principles used in the preparation of the consolidated financial statements.
Purchase Price Allocation—As a result of the Patina Merger in 2005 and the acquisition of U.S. Exploration in
2006, we acquired assets and assumed liabilities in transactions accounted for as purchases. In connection with a
purchase business combination, the acquiring company must allocate the cost of the acquisition to assets acquired
and liabilities assumed based on fair values as of the acquisition date. Deferred taxes must be recorded for any
differences between the assigned values and tax bases of assets and liabilities. Any excess of purchase price over
amounts assigned to assets and liabilities is recorded as goodwill. The amount of goodwill recorded in any particular
business combination can vary significantly depending upon the value attributed to assets acquired and liabilities
assumed.
In estimating the fair values of assets acquired and liabilities assumed we made various assumptions. The most
significant assumptions related to the estimated fair values assigned to proved and unproved crude oil and natural
gas properties. To estimate the fair values of these properties, we prepared estimates of crude oil and natural gas
reserves. We estimated future prices to apply to the estimated reserve quantities acquired, and estimated future
operating and development costs, to arrive at estimates of future net cash flows. For estimated proved reserves, the
future net cash flows were discounted using a market-based weighted average cost of capital rate determined
appropriate at the time of the merger. The market-based weighted average cost of capital rate was subjected to
additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved
reserves, the discounted future net cash flows of probable and possible reserves were reduced by additional risk-
weighting factors.
Estimated deferred taxes were based on available information concerning the tax basis of assets acquired and
liabilities assumed and loss carryforwards at the merger date, although such estimates may change in the future as
additional information becomes known.
While the estimates of fair value for the assets acquired and liabilities assumed have no effect on our cash flows,
they can have an effect on the future results of operations. Generally, higher fair values assigned to crude oil and
natural gas properties result in higher future depreciation, depletion and amortization (“DD&A”) expense, which
results in decreased future net earnings. Also, a higher fair value assigned to crude oil and natural gas properties,
based on higher estimates of future crude oil and natural gas prices, could increase the likelihood of impairment in
29
the event of lower commodity prices or higher operating or development costs than those originally used to
determine fair value. Impairment would have no effect on cash flows but would result in a decrease in net income
for the period in which the impairment is recorded.
Goodwill—As of December 31, 2007, the consolidated balance sheet included $760 million of goodwill, all of
which has been assigned to the US reporting unit. Goodwill is not amortized to earnings but is tested, at least
annually, for impairment at the reporting unit level. We conduct the goodwill impairment test as of December 31 of
each year. Other events and changes in circumstances may also require goodwill to be tested for impairment
between annual measurement dates. If the carrying value of goodwill is determined to be impaired, the amount of
goodwill is reduced and a corresponding charge is made to earnings in the period in which the goodwill is
determined to be impaired.
The impairment assessment requires management to make estimates regarding the fair value of the reporting unit to
which goodwill has been assigned. The fair value of the US reporting unit was determined using a combination of
the income approach and the market approach. Under the income approach, the fair value of the reporting unit is
estimated based on the present value of expected future cash flows. Under the market approach, the fair value is
estimated based on selected financial metrics.
The income approach is dependent on a number of factors including estimates of forecasted revenue and operating
costs, proved reserves, as well as the success of future exploration for and development of unproved reserves,
appropriate discount rates and other variables. Downward revisions of estimated reserve quantities, increases in
future cost estimates, divestiture of a significant component of the reporting unit, or sustained decreases in natural
gas or crude oil prices could lead to an impairment of all or a portion of goodwill in future periods. Under the market
approach, we make certain judgments about the selection of comparable companies, comparable recent company
and asset transactions and transaction premiums. Although we have based the fair value estimate on assumptions we
believe to be reasonable, those assumptions are inherently unpredictable and uncertain and actual results could differ
from the estimate. In 2007, no goodwill impairment was recognized.
When we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we include goodwill
associated with that business in the carrying amount of the business in order to determine the gain or loss on
disposal. The amount of goodwill to be included in that carrying amount is based on the relative fair value of the
business to be disposed of and the portion of the reporting unit that will be retained. During 2006, we allocated
$100 million of US reporting unit goodwill to the carrying amount of our Gulf of Mexico shelf properties sold. The
amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or
loss recognized on the sale of that business.
Reserves—All of the reserve data in this Form 10-K are estimates. Estimates of our crude oil and natural gas
reserves are prepared by our engineers in accordance with guidelines established by the SEC. Reservoir engineering
is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous
uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Uncertainties include the
projection of future production rates and the expected timing of development expenditures. The accuracy of any
reserve estimate is a function of the quality of available data and of engineering and geological interpretation and
judgment. As a result, reserve estimates may be different from the quantities of crude oil and natural gas that are
ultimately recovered. Estimates of proved crude oil and natural gas reserves significantly affect our DD&A expense.
For example, if estimates of proved reserves decline, the DD&A rate will increase, resulting in a decrease in net
income. A decline in estimates of proved reserves could also trigger an impairment analysis to determine if the
carrying amount of crude oil and natural gas properties exceeds fair value and could result in an impairment charge,
which would reduce earnings. In addition, a decline in estimates of proved reserves could trigger a goodwill
impairment analysis.
Oil and Gas Properties—We account for crude oil and natural gas properties under the successful efforts method of
accounting. The alternative method of accounting for crude oil and natural gas properties is the full cost method.
Under the successful efforts method, costs to acquire mineral interests in crude oil and natural gas properties, to drill
and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized.
Proved property acquisition costs are amortized to operations by the unit-of-production method on a property-by-
property basis based on total proved crude oil and natural gas reserves as estimated by our engineers. Costs to drill
and equip exploratory wells that find proved reserves and to drill and equip development wells are also amortized to
operations by the unit-of-production method on a property-by-property basis. They are amortized based on proved
developed crude oil and natural gas reserves. Application of the successful efforts method results in the expensing of
30
certain costs including geological and geophysical costs, exploratory dry holes and delay rentals, during the periods
the costs are incurred. Under the full cost method, these costs are capitalized as assets and charged to earnings in
future periods as a component of DD&A expense. In addition, under the full cost method capitalized costs are
accumulated in pools on a country-by-country basis. DD&A is computed on a country-by-country basis, and
capitalized costs are limited on the same basis through the application of a ceiling test. We believe the successful
efforts method is the most appropriate method to use in accounting for our crude oil and natural gas properties as
this method is better aligned with our business strategy. If we had used the full cost method, our financial position
and results of operations could have been significantly different.
Exploratory Well Costs—In accordance with the successful efforts method of accounting, the costs associated
with drilling an exploratory well may be capitalized temporarily, or “suspended,” pending a determination of
whether commercial quantities of crude oil or natural gas have been discovered. We will carry the costs of an
exploratory well as an asset if the well found a sufficient quantity of reserves to justify its completion as a
producing well and as long as we are making sufficient progress assessing the reserves and the economic and
operating viability of the project. For certain capital-intensive deepwater Gulf of Mexico or international projects,
it may take more than one year to evaluate the future potential of the exploration well and make a determination
of its economic viability. Our ability to move forward on a project may be dependent on gaining access to
transportation or processing facilities or obtaining permits and government or partner approval, the timing of
which is beyond our control. In such cases, exploratory well costs remain suspended as long as we are actively
pursuing access to necessary facilities and access to such permits and approvals and believe they will be obtained.
Management assesses the status of suspended exploratory well costs on a quarterly basis. These costs may be
charged to exploration expense in future periods if we decide not to pursue additional exploratory or development
activities. At December 31, 2007, the balance of property, plant and equipment included $249 million of suspended
exploratory well costs, $62 million of which had been capitalized for a period greater than one year. The wells
relating to these suspended costs continue to be evaluated by various means including additional seismic work,
drilling additional wells, or evaluating the potential of the exploration wells. For more information, see Item 8.
Financial Statements and Supplementary Data—Note 5—Capitalized Exploratory Well Costs.
Impairment of Proved Oil and Gas Properties—We assess proved crude oil and natural gas properties for possible
impairment when events or circumstances indicate that the recorded carrying value of the properties may not be
recoverable. We recognize an impairment loss as a result of a triggering event and when the estimated undiscounted
future cash flows from a property are less than the carrying value. If impairment is indicated, the cash flows are
discounted at a rate approximate to our cost of capital and compared to the carrying value for determining the
amount of the impairment loss to record. Estimated future cash flows are based on management’s expectations for
the future and include estimates of crude oil and natural gas reserves and future commodity prices and operating
costs. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising
operating costs could result in a reduction in undiscounted future cash flows and could indicate property impairment.
We recorded approximately $4 million of impairments in 2007, primarily related to adjustment of the carrying value
of properties to their fair values.
Impairment of Unproved Oil and Gas Properties—We also perform periodic assessments of individually significant
unproved crude oil and natural gas properties for impairment. Cash flows used in the impairment analysis are
determined based upon management’s estimates of natural gas and crude oil reserves, future commodity prices and
future costs to extract the reserves. Downward revisions in estimated reserve quantities, reductions in commodity
prices, or increases in estimated costs could cause a reduction in the value of an unproved property and, therefore,
could also cause a reduction in the carrying amounts of the property. If undiscounted future net cash flows are less
than the carrying value of the property, indicating impairment, the cash flows are discounted at a rate approximate to
our cost of capital and compared to the carrying value for determining the amount of the impairment loss to record.
The estimated prices used in the cash flow analysis are determined by management based on forward price curves
for the related commodities, adjusted for average historical location and quality differentials. Estimates of cash
flows related to probable and possible reserves are reduced by additional risk-weighting factors. Due to the volatility
of natural gas and crude oil prices, these cash flow estimates are inherently imprecise. Management’s assessment of
the results of exploration activities, availability of funds for future activities and the current and projected political
climate in areas in which we operate also impact the amounts and timing of impairment provisions. During 2007, we
recorded impairments of significant unproved oil and gas properties totaling approximately $3 million in exploration
expense.
31
Asset Retirement Obligation—Our asset retirement obligations (“ARO”) consist of estimated costs of
dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties.
Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations,”
requires that the discounted fair value of a liability for an ARO be recognized in the period in which it is incurred
with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The
recognition of an ARO requires that management make numerous estimates, assumptions and judgments
regarding such factors as the existence of a legal obligation for an ARO; estimated probabilities, amounts and
timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. In periods subsequent to
initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the
passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash
flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related
capitalized cost, including revisions thereto, is charged to expense through DD&A. See Item 8. Financial
Statements and Supplementary Data—Note 6—Asset Retirement Obligations.
Involuntary Conversions—When an involuntary conversion occurs, such as the destruction of oil and gas producing
assets by a hurricane, a loss is accrued by a charge to income if the amount of loss can be reasonably estimated. An
asset relating to insurance recovery is recognized only when realization of the claim for recovery of a loss
recognized in the financial statements is deemed probable. A gain (recovery of a loss not yet recognized in the
financial statements or an amount recovered in excess of a loss recognized in the financial statements) is not
recognized until the insurance reimbursement has been received.
Management must make a number of estimates and assumptions relating to these gain and loss accruals. These
include estimated costs of salvage, clean-up, restoration, redevelopment or abandonment and estimated amounts of
insurance recoveries. The amount of an insurance recovery may be limited if total industry claims are in excess of
the insurance carrier’s ceiling limitation per event. A significant amount of time may be necessary for an insurance
carrier to review all related claims for an event and determine the company-specific claim limitation on the final
recovery. In addition, we may continue to incur costs, submit claims and receive reimbursements over a multi-year
period.
The estimates involved in this process can have significant effects on reported amounts of net income. A decrease in
the estimated amount of insurance recoveries will result in an increase in the involuntary conversion loss, which will
result in a decrease in net income. An increase in estimated costs of salvage, if not covered by insurance, will also
result in an increase in the involuntary conversion loss, which will result in a decrease in net income. Unreimbursed
losses will have a negative effect on our cash flows. During the first half of 2007, several factors contributed to an
increase in our estimated cleanup costs for damage related to Hurricanes Ivan and Katrina. These factors included
cost escalation due to weather delays and an increase in effort for the design and construction of the deck lifting
barge and mooring system, as well as additional costs for the actual deck lifting activities. These increases caused
the total project costs, combined with net book value of the assets destroyed, to exceed certain insurance coverage
limitations. As a result, we recorded $51 million as a loss on involuntary conversion during 2007. See Item 8.
Financial Statements and Supplementary Data—Note 4—Effect of Gulf Coast Hurricanes.
Derivative Instruments and Hedging Activities—We use various derivative instruments to minimize the impact of
commodity price fluctuations on forecasted sales of crude oil and natural gas production. We also use derivative
instruments in connection with purchases and sales of third-party production to lock in profits or limit exposure to
commodity price risk. In addition, we have used derivative instruments in connection with acquisitions and certain
price-sensitive projects. Management exercises significant judgment in determining types of instruments to be used,
production volumes to be hedged, prices at which to hedge and the counterparties’ creditworthiness. We account for
derivative instruments under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities, as
amended”. For derivative instruments that qualify as cash flow hedges, changes in fair value, to the extent the hedge
is effective, are recognized in accumulated other comprehensive income or loss (“AOCL”) until the hedged
forecasted transaction is recognized in earnings. Therefore, prior to settlement of the derivative instruments, changes
in the fair market value of those derivative instruments can cause significant increases or decreases in AOCL. For
derivative instruments that do not qualify as cash flow hedges, changes in fair value are reported in current period
net income and therefore can result in significant increases or decreases in current period net income. All hedge
ineffectiveness is recognized in the current period in net income. Ineffectiveness is the amount of gains or losses
from derivative instruments which are not offset by corresponding and opposite gains or losses on the expected
future transaction. Regression analysis is performed on initial assessment of the hedge and subsequently every
quarter thereafter in order to determine that the hedge instrument will be or has been highly effective in offsetting
32
gains or losses on the future transaction. As discussed in Item 8. Financial Statements and Supplementary Data—Note
2—Summary of Significant Accounting Policies, we voluntarily discontinued cash flow hedge accounting for our commodity
derivative instruments, effective January 1, 2008. Such a change did not affect our net assets or cash flows at December
31, 2007 and will not require adjustments to our previously reported financial statements. However, the use of mark-
to-market accounting for our commodity derivatives will likely add volatility to our reported earnings.
We occasionally enter into forward contracts or swap agreements to hedge exposure to interest rate risk. Changes in
fair value of interest rate swaps or interest rate “locks” used as cash flow hedges are reported in AOCL, to the extent
the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to
interest expense over the term of the related notes. See Item 8. Financial Statements and Supplementary Data—Note
12—Derivatives and Hedging Activities.
Income Tax Expense and Deferred Tax Assets—We are subject to income and other taxes in numerous taxing
jurisdictions worldwide. For financial reporting purposes, we provide taxes at rates applicable for the appropriate tax
jurisdictions. Estimates of amounts of income tax to be recorded involve interpretation of complex tax laws,
assessment of the effects of foreign taxes on domestic taxes, and estimates regarding the timing and amounts of
future repatriation of earnings from controlled foreign corporations.
The consolidated balance sheets include deferred tax assets. Deferred tax assets arise when expenses are recognized
in the financial statements before they are recognized in the tax returns or when income items are recognized in the
tax return before they are recognized in the financial statements. Deferred tax assets also arise when operating losses
or tax credits are available to offset tax payments due in future years. Ultimately, realization of a deferred tax asset
depends on the existence of sufficient taxable income within the future periods to absorb future deductible
temporary differences, loss carryforwards or credits. In assessing the realizability of deferred tax assets,
management must consider whether it is more likely than not that some portion or all of the deferred tax assets will
not be realized. Management considers all available evidence (both positive and negative) in determining whether a
valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected
future taxable income and tax planning strategies in making this assessment, and judgment is required in considering
the relative weight of negative and positive evidence. We continue to monitor facts and circumstances in the
reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized
prior to their expiration. As a result, we may determine, and we have determined in the past, that a deferred tax asset
valuation allowance should be established. Any increases or decreases in a deferred tax asset valuation allowance
would impact net income through offsetting changes in income tax expense.
Allowance for Doubtful Accounts—We assess the recoverability of all material trade and other receivables to
determine their collectibility on a quarterly basis. We accrue a reserve on a receivable when, based on
management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be
reasonably estimated. In determining the amount of the reserve, management must analyze the aging of accounts
receivable at the date of the consolidated financial statements and assess collectibility based on historic results,
current collection trends and an evaluation of economic conditions. Over the last three years, we have increased the
allowance by approximately $40 million to cover potentially uncollectible balances related to the Ecuador power
operations. Certain entities purchasing electricity in Ecuador have been slow to pay amounts due us. We are
pursuing various strategies to protect our interests including international arbitration and litigation. However, if
estimates are inaccurate, we may incur gains or losses that could have a material effect on our results of operations.
Benefit Plans—We sponsor a qualified defined benefit pension plan, a non-qualified defined benefit pension plan
(“restoration plan”), and other postretirement benefit plans. The actuarial determination of the projected benefit
obligations and related benefit expense requires that certain assumptions be made regarding such variables as
expected return on plan assets, discount rates, rates of future compensation increases, estimated future employee
turnover rates and retirement dates, distribution election rates, mortality rates, retiree utilization rates for health care
services and health care cost trend rates. The selection of assumptions requires considerable judgment concerning
future events and has a significant impact on the amount of the obligations recorded in the consolidated balance
sheets and on the amount of expense included in the consolidated statements of operations.
We base our determination of the asset return component of pension expense on a market-related valuation of assets,
which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a
five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference
between the expected return calculated using the market-related value of assets and the actual return based on the
fair value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the
33
future value of assets will be impacted as previously deferred gains or losses are recorded. As of January 1, 2007,
cumulative asset gains of approximately $3 million remained to be recognized in the calculation of the market-
related value of assets.
In selecting the assumption for expected long-term rate of return on assets, we consider the average rate of earnings
expected on the funds invested or to be invested to provide for plan benefits included in the projected benefit
obligations. This includes considering the returns being earned by the plan assets and the rates of return expected to
be available for reinvestment. We assume that the long-term asset mix will be consistent with the target asset
allocation of 70% equity and 30% fixed income, with a range of plus or minus 10% acceptable degree of variation in
asset allocation. A 1% decrease in the expected return on plan assets assumption would have increased 2007 net
periodic benefit cost by approximately $1 million. The expected return assumption used for 2007 was 8.25%.
In selecting a discount rate, employers may look to rates of return on high quality fixed-income investments
available as of the year-end measurement date and expected to be available during the period to maturity of the
pension benefits. In order to determine an appropriate December 31, 2007 discount rate, we performed an analysis
of the Citigroup Pension Discount Curve (the “CPDC”) for each of our plans. The CPDC uses spot rates that
represent the equivalent yield on high quality, zero coupon bonds for specific maturities. We used these rates to
develop an equivalent single discount rate based on our plans’ expected future benefit payment streams and duration
of plan liabilities. A 1% increase in the discount rate assumption would have decreased 2007 net periodic benefit
cost by $4 million and decreased the benefit obligation for the combined plans by $17 million at December 31,
2007. A 1% decrease in the discount rate assumption would have increased 2007 net periodic benefit cost by
$5 million and increased the benefit obligation for the combined plans by $20 million at December 31, 2007. The
assumed discount rate used to determine net periodic benefit cost for 2007 was 5.75%. The assumed discount rate
used to determine the benefit obligations at December 31, 2007 was 6.5% for our defined benefit pension and
restoration plans and 6.25% for our medical and life plans.
Effective January 1, 2008, the defined benefit pension plan and restoration plans were amended in order to provide a
lump sum option. Certain assumptions were made regarding the percentage of active participants who would elect
the lump sum option upon future termination and the percentage of existing deferred vested participants who would
elect the lump sum option during 2008. In addition, the amounts of lump sum payments are affected by mortality
and interest rate assumptions. The lump sum option increased the projected benefit obligation by $5.5 million at
December 31, 2007 and will increase 2008 net periodic benefit cost by approximately $1 million.
We adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,
an amendment of FASB Statements No. 87, 88, 106 and 132(R), as of December 31, 2006. See Item 8. Financial
Statements and Supplementary Data—Note 11—Benefit Plans.
Recently Issued Pronouncements—See Item 8. Financial Statements and Supplementary Data—Note 16—Recently
Issued Pronouncements.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Our primary cash needs are to fund capital expenditures related to the acquisition, exploration and development of
crude oil and natural gas properties, to repay outstanding borrowings or to pay other contractual commitments and
interest payments on debt and to pay dividends. Our traditional sources of liquidity are cash on hand, cash flows
from operations and available borrowing capacity under credit facilities. Funds may also be generated from
occasional sales of non-strategic crude oil and natural gas assets. We had $660 million in cash and cash equivalents
at December 31, 2007, compared with $153 million at December 31, 2006. Substantially all of this cash is located in
our foreign subsidiaries and would be subject to additional US income taxes if repatriated. The cash is denominated
in US dollars and is invested in highly liquid, investment-grade securities with original maturities of three months or
less at the time of purchase. We currently intend to use our international cash to fund international projects,
including the development of West Africa.
We are monitoring the current conditions in the credit markets. We have reviewed the creditworthiness of the banks
and financial institutions with which we maintain our investments as well as the securities underlying our
investments. Thus far, our liquidity and financial position have not been affected. We believe that losses from
nonperformance are unlikely to occur; however, we are not able to predict sudden changes in creditworthiness.
34
Our ratio of debt-to-book capital has decreased from 30% at December 31, 2006, to 28% at December 31, 2007. We
define our ratio of debt-to-book capital as total debt (which includes both long-term debt, excluding unamortized
discount, and short-term borrowings) divided by the sum of total debt plus shareholders’ equity. Significant changes
in our financial position causing a change in the ratio of debt-to-book capital include:
• a $75 million increase in total debt from the balance at December 31, 2006;
• a $944 million increase in shareholders’ equity from current year net income;
• a $102 million decrease in shareholders’ equity due to repurchase of common stock; and
• a $144 million decrease in shareholders’ equity (effected by an increase in AOCL) primarily related to an
increase in deferred hedging losses.
Cash Flows
Summary cash flow information is as follows:
Total cash provided by (used in):
Operating activities
Investing activities
Financing activities
Increase (decrease) in cash and cash equivalents
2007
Year Ended December 31,
2006
(in thousands)
2005
$
2,016,573
(1,403,089)
(107,029)
506,455
$
$
1,730,306
(1,098,339)
(588,880)
43,087
$
$
1,239,878
(1,892,488)
583,137
(69,473)
$
Operating Activities—Net cash provided by operating activities increased $286 million, or 17% during 2007 as
compared with 2006. The increase was due primarily to higher average realized crude oil prices and higher average
realized US natural gas prices. These increases were partially offset by higher exploration expense and general and
administrative (“G&A”) expense. In addition, cash flows from operating activities in 2007 included dividends from
equity method investments, which had been classified as investing cash flows in 2006. See Results of Operations—
Income from Equity Method Investees.
Net cash provided by operating activities increased $490 million, or 40%, during 2006 as compared with 2005. The
increase was due primarily to higher sales volumes and higher average realized crude oil prices, offset by lower
average realized US natural gas prices and increases in total production costs, G&A expense and interest expense.
Investing Activities—The primary use of cash in investing activities is for capital spending, which may be offset by
proceeds from property sales or dividends from equity method investees. Net cash used in investing activities
increased $305 million, or 28% during 2007 as compared with 2006. The change was due primarily to a decrease in
divestiture activity in 2007 as compared with 2006, when we sold our Gulf of Mexico shelf properties. In addition,
investing cash inflows were reduced in 2007 because distributions received from equity method investees were
included in operating cash flows. See Results of Operations—Income from Equity Method Investees.
Net cash used in investing activities decreased $794 million, or 42% during 2006 as compared with 2005. The
decrease was due primarily to a decrease in acquisition activity in 2006 as compared to the Patina Merger in 2005
and an increase in divestiture activity in 2006, due to the sale of our Gulf of Mexico shelf properties, which provided
investing cash inflows in 2006.
35
Financing Activities—Net cash used in financing activities decreased $482 million during 2007 as compared with
2006. The change was due to net increases in the credit facility during 2007 as compared with payments being made
to decrease outstanding debt during 2006. In 2007 there was also a net decrease of $297 million in amounts used to
repurchase common stock as compared with 2006. Cash flows were provided by financing activities in 2005, as
compared with 2006, and totaled $583 million. In 2005, cash was provided by borrowings under the credit facility
and exercise of stock options, partially offset by dividend payments and the repayment of debt acquired in the Patina
Merger.
Acquisition, Capital and Other Exploration Expenditures
Expenditure information (on an accrual basis) is as follows:
2007
Year Ended December 31,
2006
(in thousands)
2005
Acquisition, Capital and Other Exploration Expenditures
Lease acquisition of unproved property
Exploration expenditures
Development expenditures
Corporate and other expenditures
Total consolidated capital expenditures
Our share of equity investee development costs
Total
$
145,326
371,758
1,185,385
36,361
1,738,830
516
1,739,346
$
$
53,652
203,035
1,054,780
35,069
1,346,536
580
1,347,116
$
$
16,793
161,515
662,585
21,478
862,371
27,639
890,010
$
Total capital expenditures during 2007 increased $392 million, or 29%, as compared with 2006. The increase was
due to lease acquisition in the US, exploratory activities in West Africa and the North Sea, and increased
development activity in the Northern region and Gulf of Mexico area of our US operations. Total capital
expenditures during 2006 increased $457 million, or 51%, as compared with 2005. The increase was primarily due
to development expenditures in the US and the North Sea. Capital expenditures for 2005 included $275 million of
post-merger exploration and development-related expenditures on Patina properties.
As a result of the U.S. Exploration acquisition in 2006, we allocated $413 million to proved properties and $131
million to unproved properties. As a result of the Patina Merger in 2005, we allocated $2.6 billion to proved
properties and $1.1 billion to unproved properties.
Insurance Recoveries
See Item 8. Financial Statements and Supplementary Data—Note 4—Effect of Gulf Coast Hurricanes.
Our corporate insurance program provides up to $260 million property damage coverage per loss event. However,
our insurance carrier’s aggregation limit for catastrophic windstorm events is $750 million. If an insured
catastrophic loss event occurs, we could still recover less than our stated limits should the total aggregate losses
realized by our carrier exceed its $750 million aggregation limit applicable to any single loss event.
We carry additional property damage and control of well coverage for our deepwater Gulf of Mexico and remaining
Gulf of Mexico shelf properties. This additional insurance provides coverage only for claims in excess of $100
million, which exceed the $260 million property damage coverage or where the $260 million property damage
coverage is reduced by application of the $750 million aggregation limit. We carry business interruption insurance
for certain international locations. Effective June 2007, we no longer carry business interruption insurance for our
Gulf of Mexico operations.
Financing Activities
Long-Term Debt—Our long-term debt totaled $1.9 billion (excluding unamortized discount) at December 31, 2007.
Maturities range from 2009 to 2097. Our principal source of liquidity is an unsecured revolving credit facility (the
“Credit Facility”). In November 2007, we extended the Credit Facility until December 9, 2012. The commitment is
$2.1 billion until December 9, 2011 at which time the commitment reduces to $1.8 billion. The Credit Facility
(i) provides for Credit Facility fee rates that range from 5 basis points to 15 basis points per year depending upon our
credit rating, (ii) makes available short-term loans up to an aggregate amount of $300 million and (iii) provides for
36
interest rates that are based upon the Eurodollar rate plus a margin that ranges from 20 basis points to 70 basis points
depending upon our credit rating and utilization of the Credit Facility.
The Credit Facility contains customary representations and warranties and affirmative and negative covenants. The
Credit Facility requires that our total debt to capitalization ratio (as defined in the credit agreement), expressed as a
percentage, not exceed 60% at any time. A violation of this covenant could result in a default under the Credit
Facility, which would permit the participating banks to restrict our ability to access the Credit Facility and require
the immediate repayment of any outstanding advances under the Credit Facility. At December 31, 2007, the total
debt to capitalization ratio was 28%, calculated for this purpose as total debt divided by the sum of total debt plus
shareholders’ equity.
The Credit Facility is with certain commercial lending institutions and is available for general corporate purposes.
At December 31, 2007, $1.2 billion in borrowings were outstanding under the Credit Facility. The weighted average
interest rate applicable to borrowings under the Credit Facility at December 31, 2007 was 5.28%.
We also have $650 million of fixed-rate debt outstanding at December 31, 2007 with a weighted average interest
rate of 6.92%. Maturities range from 2014 to 2097.
Installment Payments Due—During 2007, we purchased working interests in oil and gas properties in the Piceance
basin of western Colorado for $75 million. After making an initial cash payment of $25 million, we owe $50 million
in the form of installment payments to the seller. Installments of $25 million each are due on May 12, 2008 and May
11, 2009. The amount due in 2008 is included in short-term borrowings and the amount due in 2009 is included in
long-term debt in the consolidated balance sheets. Interest on the unpaid amounts is due quarterly. Interest accrues at
a LIBOR rate plus .30%. The interest rate was 5.53% at December 31, 2007.
Short-Term Borrowings—Our Credit Facility is supplemented by short-term borrowings under various uncommitted
credit lines used for working capital purposes. Uncommitted credit lines may be offered by certain banks from time
to time at rates negotiated at the time of borrowing. Other than the installment payments discussed above, there were
no short-term borrowings outstanding at December 31, 2007.
Interest Rate Locks—We occasionally enter into forward contracts or swap agreements to hedge exposure to interest
rate risk. As of December 31, 2007, we had entered into two interest rate locks which are scheduled to expire third
quarter 2008. See Item 8. Financial Statements and Supplementary Data—Note 7—Debt.
Cash Interest Payments—We made cash interest payments, net of capitalized interest, of $105 million in 2007,
$106 million in 2006 and $84 million in 2005.
Common Stock Repurchase Program—During 2007 we completed a common stock repurchase program authorized
by our Board of Directors in 2006. We repurchased two million shares of our common stock at an aggregate cost of
$101 million in 2007 and 8.4 million shares of our common stock at an aggregate cost of $399 million in 2006,
resulting in a total of 10.4 million shares acquired at an average price of $48.17 per share.
Dividends—We paid cash dividends totaling 43.5 cents per common share in 2007, 27.5 cents per common share in
2006 and 15 cents per common share in 2005. On January 22, 2008, the Board of Directors declared a quarterly cash
dividend of 12.0 cents per common share, which was paid February 19, 2008 to shareholders of record on
February 4, 2008. The amount of future dividends will be determined on a quarterly basis at the discretion of the
Board of Directors and will depend on earnings, financial condition, capital requirements and other factors.
Exercise of Stock Options—Proceeds from the exercise of stock options totaled $25 million in 2007, $63 million in
2006 and $68 million in 2005. Proceeds received from the exercise of stock options fluctuate primarily based on the
number of options exercised which is influenced by the price at which our common stock trades on the NYSE in
relation to the exercise price of the options issued.
37
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet
obligations. As of December 31, 2007, the material off-balance sheet arrangements and transactions that we have
entered into included drilling service contracts, operating lease agreements, undrawn letters of credit and derivative
contracts. Other than the off-balance sheet arrangements listed above, we have no transactions, arrangements or
other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our
liquidity or availability of or requirements for capital resources. See Contractual Obligations below for more
information regarding off-balance sheet arrangements.
Contractual Obligations
The following table summarizes certain contractual obligations that are reflected in the consolidated balance sheets
and/or disclosed in the accompanying notes. See Item 8. Financial Statements and Supplementary Data—Notes to
Consolidated Financial Statements.
Total
2008
Payments Due by Period
2009
and 2010
(in thousands)
2011
and 2012
2013
and Beyond
Long-term debt (excludes interest) (1)
Drilling and equipment obligations (2) :
United States drilling and equipment
International drilling and equipment
Purchase obligations (3)
Throughput agreement (4)
Operating lease obligations (5) :
Office buildings and facilities
Oil and gas operations equipment
Other long-term liabilities (6) :
Asset retirement obligations (7)
Derivative instruments (8)
Total contractual obligations
$
1,880,000
$
25,000
$
25,000
$
1,180,000
$
650,000
462,759
68,170
194,419
95,000
52,894
12,074
181,337
68,170
194,419
-
173,935
-
-
38,000
7,289
5,467
14,495
6,607
107,487
-
-
38,000
13,247
-
-
-
-
19,000
17,863
-
144,288
603,133
3,512,737
$
13,332
525,159
1,020,173
$
12,443
77,974
348,454
$
13,034
-
1,351,768
$
105,479
-
792,342
$
(1) Based on the total debt balance outstanding at December 31, 2007, scheduled maturities and interest rates in
effect at December 31, 2007, our cash payments for interest would be $109 million in 2008, $108 million in
2009, $107 million in 2010, $107 million in 2011, $107 million in 2012 and $990 million for the remaining
years for a total of $1.5 billion. See Item 8. Financial Statements and Supplementary Data—Note 7—Debt for
additional information regarding our long-term debt obligations.
(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 facilities. See Item
8. Financial Statements and Supplementary Data—Note 14—Commitments and Contingencies for additional
information regarding our drilling and equipment obligations.
(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 14—Commitments and Contingencies for additional information
regarding our purchase obligations.
In January 2007, we entered into a five-year throughput agreement. The transporting pipeline is expected to be
completed and operational in 2009. See Item 8. Financial Statements and Supplementary Data—Note 14—
Commitments and Contingencies for additional information regarding our throughput agreement.
(4)
38
(5) 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 14—Commitments and Contingencies for additional information regarding our operating lease
obligations.
(6) The table does not include our deferred compensation liabilities of $225 million and our accrued benefit costs
of $51 million as specific payment dates are unknown. See Item 8. Financial Statements and Supplementary
Data—Note 11—Benefit Plans for additional information on our deferred compensation liability and our
accrued benefit costs.
(7) Asset retirement obligations are discounted. See Item 8. Financial Statements and Supplementary Data—Note
6—Asset Retirement Obligations for additional information on our asset retirement obligations.
(8) See Item 8. Financial Statements and Supplementary Data—Note 12—Derivative Instruments and Hedging
Activities for additional information on our derivative instrument obligations.
We accrued approximately $12 million as of December 31, 2007, for an insurance contingency due to our
membership in Oil Insurance Limited (OIL). OIL is a mutual insurance company which insures specific property,
pollution liability and other catastrophic risks. As part of our membership, we are contractually committed to pay
termination fees should we elect to withdraw from OIL. We do not anticipate withdrawing from OIL; however, the
potential termination fee is calculated annually based on OIL’ s past losses and the liability reflecting this potential
charge has been accrued.
In addition, in the ordinary course of business, we maintain letters of credit in support of certain performance
obligations of our subsidiaries. Outstanding letters of credit totaled approximately $1 million at December 31, 2007.
Other
Contributions to Pension and Other Postretirement Benefit Plans—We made contributions to the pension,
restoration and other postretirement benefit plans totaling $12 million during 2007, $36 million during 2006, and
$14 million during 2005. The actual return on plan assets was $13 million in both 2007 and 2006. The investment
return has tended to follow market performance. In August 2006, the Pension Protection Act of 2006 (the Act) was
signed into law. Certain provisions of this Act changed the calculation related to the maximum contribution amount
deductible for income tax purposes and require that pension plans become fully funded over a seven-year period
beginning in 2008. As a result of previous contributions made to the pension plan, there are no required
contributions expected during 2008. We may, however, make additional contributions to our pension plan. We
expect to make contributions of $4 million to the unfunded restoration and medical and life plans in 2008. This
amount is equal to the benefits expected to be paid by those plans.
Income Taxes—We made cash payments for income taxes, net of refunds, of $149 million during 2007, $115 million
during 2006 and $122 million during 2005.
Contingencies—During 2007, we paid a total of $56 million to settle legal proceedings; these amounts had been
accrued previously. During 2006 and 2005, no significant payments were made to settle any legal proceedings. We
regularly analyze current information and accrue for probable liabilities on the disposition of certain matters, as
necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded
when it is probable that a liability has been incurred and the amount can be reasonably estimated.
RESULTS OF OPERATIONS
Net Income
Net income for 2007 was $944 million, a 39% increase over 2006. Factors contributing to the increase in net income
from 2006 to 2007 included:
• a $332 million, or 11%, increase in total revenues, due primarily to higher average realized crude oil prices
and higher average realized US natural gas prices and an increase in income from equity method investees;
• a $395 million decrease in loss on derivative instruments; and
offset by:
• a $208 million decrease in gains from asset sales;
• a $105 million increase in DD&A expense;
• a $51 million loss on involuntary conversion expense; and
• a $51 million increase in oil and gas exploration expense.
39
Net income for 2006 was $678 million, a 5% increase over 2005. Factors contributing to the increase in net income
from 2005 to 2006 included:
• a $753 million, or 34%, increase in total revenues, driven primarily by a full year of Patina operations and
nine months of U.S. Exploration operations and higher average realized oil prices;
• an increase of $215 million in gains from asset sales;
offset by:
• an increase in loss on derivative instruments of $360 million; and
• a $232 million increase in DD&A expense.
Natural Gas Information
2007
Year Ended December 31,
2006
(in thousands)
2005
Natural gas sales
$
1,271,866
$
1,211,782
$
1,023,644
Average daily natural gas sales volumes and average realized sales prices were as follows:
2007
Year Ended December 31,
2006
2005
Mcfpd
$/Mcf
Mcfpd
$/Mcf
Mcfpd
$/Mcf
North America (1)
West Africa (2)
North Sea
Israel
Ecuador (3)
Other International
412,212
132,464
6,235
110,820
25,713
-
$
7.51
451,712
$
6.61
343,953
$
7.43
0.29
6.54
2.79
-
-
45,422
8,130
92,894
24,475
294
0.37
8.00
2.72
-
0.96
65,581
9,299
66,377
22,795
190
0.25
5.93
2.68
-
1.10
Total
687,444
$
5.26
622,927
$
5.55
508,195
$
5.78
(1) Reflects an increase of $1.12 per Mcf in 2007 and reductions of $0.25 per Mcf in 2006 and $0.77 per Mcf in
2005 from hedging activities.
(2) 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 facility. The methanol and LPG plants are owned by affiliated entities
accounted for under the equity method of accounting. The volumes sold by the LPG plant are included in the
table below under crude oil information. Natural gas volumes include sales to an LNG facility of 78,090 Mcfpd
2007; there were no natural gas sales to the LNG facility before 2007. The natural gas sold to the LNG facility
and methanol plant has a lower Btu content than the natural gas sold to the LPG plant. As a result of the natural
gas volumes sold to the LNG plant in 2007, the average price received on an Mcf basis is lower. For 2007 and
2006, the price on an Mcf basis has been adjusted to reflect the Btu content on gas sales.
(3) The natural gas-to-power project in Ecuador is 100% owned by one of our subsidiaries, and intercompany
natural gas sales are eliminated for accounting purposes. Electricity sales included in total revenues totaled $71
million in 2007, $72 million in 2006 and $74 million in 2005.
2007 Compared with 2006—Natural gas sales increased a net $60 million, or 5%, during 2007 as compared with
2006. The increase was affected by both volume and price changes. In the US, natural gas sales increased $40
million from the previous year despite lower sales volumes. Deepwater Gulf of Mexico volumes were slightly
higher than 2006, while development activity in the Piceance basin and a full year of production from U.S.
Exploration properties acquired in 2006 resulted in increased production in the Northern region. However, the Gulf
Coast onshore area had lower production due to natural field decline, and there was a loss of production due to the
sale of our Gulf of Mexico shelf properties in 2006. The Northern region also experienced a temporary decline in
production due to third party processing downtime and inclement weather. The net production decrease was more
than offset by a 14% increase in average realized natural gas prices.
40
Internationally, West Africa natural gas sales increased $8 million from the previous year. Natural gas volumes were
higher due to increased sales of natural gas from the Alba field in Equatorial Guinea; however, the effect of higher
production was somewhat offset by lower average realized gas prices. In the North Sea, natural gas production
decreased 23% as compared with the prior year primarily due to natural field decline. Lower production, combined
with lower average realized prices, resulted in a $9 million decrease in North Sea natural gas sales. In Israel, natural
gas sales increased $21 million due to record sales volumes. There was a full year of sales to Israeli Electric
Company’s Reading power plant in Tel Aviv, as well as the start up of sales to a desalinization plant and a paper
mill.
2006 Compared with 2005—Natural gas sales increased a net $188 million, or 18%, during 2006 as compared with
2005. Again, the change was caused by both significant volume and price changes. In the US natural gas sales
increased by $157 million from the previous year due to additional US production from Patina properties acquired in
2005 and from U.S. Exploration properties acquired in May 2006. In addition, there were increases in deepwater
Gulf of Mexico production where three new developments came on stream at Swordfish, Ticonderoga and Lorien.
However, increases due to higher gas sales volumes were partially offset by lower average realized prices.
Internationally, West Africa natural gas sales were flat year-to-year; however, there was a decline in sales volumes
due to the turnaround of the AMPCO methanol plant in Equatorial Guinea. The turnaround lasted 57 days and was
followed by reduced production levels caused by 35 days of compressor repairs. The production decline was
completely offset by an increase in average realized natural gas prices. In the North Sea, natural field decline
resulted in reduced sales volumes, but this reduction was more than offset by the increase in average realized prices.
Israel experienced a $4 million increase in natural gas sales primarily due to increased demand from Israel Electric
Corporation Limited, a full year of sales to Bazan Oil Refinery and commencement of natural gas sales to the
Reading power plant in Tel Aviv, Israel.
Natural Gas Hedging Activities—Natural gas sales are net of the effects of derivative contracts that are accounted
for as cash flow hedges and included an increase of $169 million in 2007, and a reduction of $42 million in 2006
and $97 million in 2005 from hedging activities. Natural gas sales in 2007 include a $182 million non-cash increase
related to hedge contracts that were redesignated at the time of the Gulf of Mexico shelf property sale in 2006 and
settled during 2007. See Item 8. Financial Statements and Supplementary Data—Note 12—Derivative Instruments
and Hedging Activities.
Crude Oil Information
2007
Year Ended December 31,
2006
(in thousands)
2005
Crude oil sales
$
1,694,233
$
1,489,459
$
942,778
Average daily crude oil sales volumes and average realized sales prices were as follows:
2007
Year Ended December 31,
2006
Production (1)
Bopd
Sales
Bopd
$/Bbl
Production (1)
Bopd
Sales
2005
Sales (2)
Bopd
$/Bbl
Bopd
$/Bbl
United States (3)
West Africa (4)
North Sea
Other International (5)
Total Consolidated Operations
Equity Investees (6)
Total
42,332
15,523
12,813
6,806
77,474
8,014
85,488
42,332
15,070
12,505
6,674
76,581
7,684
84,265
53.22
71.27
76.47
53.69
60.61
55.09
60.10
45,798
17,326
3,988
7,491
74,603
7,531
82,134
45,798
17,860
3,717
7,540
74,915
8,032
82,947
50.68
62.51
67.43
52.05
54.47
45.83
53.64
25,941
17,786
5,380
7,851
56,958
3,240
60,198
46.67
42.51
52.68
42.37
45.35
43.43
45.25
$
$
$
$
$
$
41
(1) The variance between production and sales volumes is attributable to the timing of liquid hydrocarbon tanker
liftings.
(2) Sales volumes equal production volumes in 2005.
(3) Reflects reductions of $13.68 per Bbl in 2007, $11.41 per Bbl in 2006 and $8.03 per Bbl in 2005 from hedging
activities.
(4) Reflects reductions of $2.19 per Bbl in 2007 and $9.93 per Bbl in 2005 from hedging activities. We did not
hedge West Africa crude oil sales in 2006.
(5) Other international includes China and Argentina.
(6) Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea. LPG sales volumes
totaled 5,848 Bopd in 2007, 6,294 Bopd in 2006 and 2,328 Bopd in 2005.
2007 Compared with 2006—Crude oil sales increased a net $205 million, or 14%, during 2007 as compared with
2006. The increase was affected by both volume and price changes. In the US, crude oil sales declined by $25
million from the previous year. Deepwater Gulf of Mexico volumes were lower due to well performance, third-party
facility restrictions and storm shut-in. The Gulf Coast onshore area had lower production due to natural field decline,
and there was a loss of production due to the sale of our Gulf of Mexico shelf properties in 2006. Northern region
production was negatively impacted by severe winter weather in the Rocky Mountains during the first and fourth
quarters of 2007. However, development activity in the Wattenberg field, as well as a full year of production from
U.S. Exploration properties acquired in 2006, resulted in increased production in our Northern region, and the
overall US volume decline was partially offset by higher average realized prices.
Internationally, West Africa crude oil sales declined by $15 million from the previous year. Volumes declined due to
increased downtime and lower condensate yields in Equatorial Guinea, but the decline was offset by substantially
higher average realized crude oil prices. In January 2007, production began at the Dumbarton development in the
North Sea, and, as a result, crude oil production was more than triple that of the prior year. North Sea crude oil sales
increased $257 million over 2006 due to the increased volumes and, to a lesser extent, higher average realized
prices. Other international crude oil sales declined $12 million. China experienced lower volumes due to facility
downtime and natural field decline.
2006 Compared with 2005—Crude oil sales increased a net $547 million, or 58%, during 2006 as compared with
2005. Again, the increase was caused by significant volume and price changes. In the US crude oil sales increased
by $405 million from the previous year due to additional US production from Patina properties acquired in 2005 and
from U.S. Exploration properties acquired in May 2006. In addition, there were increases in deepwater Gulf of
Mexico production where three new developments came on stream at Swordfish, Ticonderoga and Lorien.
Internationally, higher average realized prices resulted in an increase of $132 million in West Africa crude oil sales
and contributed to most of the $22 million increase in other international crude oil sales. The North Sea experienced
a $12 million decrease in crude oil sales. Natural field decline and timing of tanker liftings resulted in lower sales
volumes, the effect of which was mitigated by an increase in average realized crude oil prices.
Crude Oil Hedging Activities—Crude oil sales are net of the effects of derivative contracts that are accounted for as
cash flow hedges and included a reduction of $223 million in 2007, $191 million in 2006 and $140 million in 2005
from hedging activities. See Item 8. Financial Statements and Supplementary Data—Note 12—Derivative
Instruments and Hedging Activities.
Commodity Derivative Instruments and Hedging Activities
We use various derivative instruments in connection with anticipated crude oil and natural gas sales to minimize the
impact of product price fluctuations. Such instruments include variable to fixed price swaps, costless collars and
basis swaps. Although these derivative instruments expose us to credit risk, we monitor the creditworthiness of
counterparties and believe that losses from nonperformance are unlikely to occur. Hedging gains and losses related
to crude oil and natural gas production are recorded in oil and gas sales. See Item 7A. Quantitative and Qualitative
Disclosures About Market Risk—Commodity Price Risk and Item 8. Financial Statements and Supplementary
Data—Note 12—Derivative Instruments and Hedging Activities.
42
Income from Equity Method Investees
We own a 45% interest in AMPCO, which owns and operates a methanol plant and related facilities and a 28%
interest in Alba Plant, which owns and operates an LPG processing plant. The plants and related facilities are
located in Equatorial Guinea. We account for investments in entities that we do not control but over which we exert
significant influence using the equity method of accounting. Our share of operations of equity method investees was
as follows:
Net income (in thousands):
AMPCO and affiliates
Alba Plant
Distributions/dividends (in thousands):
AMPCO and affiliates
Alba Plant
Sales volumes (1):
Methanol (Kgal)
Condensate (Bopd)
LPG (Bpd)
Production volumes (1):
Condensate (Bopd)
LPG (Bpd)
Average realized prices:
Methanol (per gallon)
Condensate (per Bbl)
LPG (per Bbl)
Year Ended December 31,
2006
2005
2007
$ 82,877
128,051
$ 38,024
101,338
$ 56,896
33,916
96,483
132,251
37,350
155,158
59,625
-
160,540
1,836
5,848
109,942
1,738
6,294
162,446
912
2,328
1,860
6,154
1,730
5,801
912
2,328
$ 1.09
74.87
48.87
$ 0.90
66.60
40.10
$ 0.77
55.76
38.63
(1) The variance between production and sales volumes is attributable to the timing of liquid hydrocarbon tanker
liftings.
Net income from AMPCO and affiliates increased substantially in 2007 relative to 2006 due to a 46% increase in
methanol sales volumes and a 21% increase in average realized methanol prices. The increase in methanol sales
volumes was due to a 57-day shutdown of methanol production for the plant turnaround that occurred during May
and June 2006 followed by 35 days of compressor repairs.
Net income from AMPCO and affiliates decreased 33% in 2006 relative to 2005 due to a 32% decrease in methanol
sales volumes offset by a 17% increase in average realized methanol prices. The decrease in methanol sales volumes
was due to the 57-day shutdown of methanol production for the plant turnaround that occurred during May and June
2006 followed by 35 days of compressor repairs. No such shutdown or plant turnaround occurred during 2005.
Net income from Alba Plant increased 26% in 2007 relative to 2006 due to a 22% increase in average realized LPG
prices and a 12% increase in average realized condensate prices.
Net income from Alba Plant increased substantially in 2006 relative to 2005 due to an almost threefold increase in
LPG sales volumes, an almost twofold increase in condensate sales volumes and a 19% increase in average realized
condensate prices. The increases in LPG and condensate sales volumes reflected the completion and ramp up to full
production of the Phase 2B liquids expansion project.
For 2007, $132 million received from Alba Plant was classified within operating cash flows as a dividend from
equity method investee as compared with 2006 in which the distributions were classified within investing cash flows
as a repayment of a loan. The change in classification was the result of all outstanding loans being repaid to us by
Alba Plant in December 2006.
43
Costs and Expenses
Production Costs—Production costs were as follows:
Total
United
States
West
North
Africa
Sea
(in thousands)
Israel
Other Int'l/
Corporate (2)
Year Ended December 31, 2007
Oil and gas operating costs (1)
Workover and repair expense
Lease operating expense
Production and ad valorem taxes
Transportation expense
Total production costs
Year Ended December 31, 2006
Oil and gas operating costs (1)
Workover and repair expense
Lease operating expense
Production and ad valorem taxes
Transportation expense
Total production costs
Year Ended December 31, 2005
Oil and gas operating costs (1)
Workover and repair expense
Lease operating expense
Production and ad valorem taxes
Transportation expense
Total production costs
$
299,622
22,830
322,452
113,547
51,699
487,698
$
190,723
22,516
213,239
91,225
39,542
344,006
$
$
$
$
270,136
46,951
317,087
108,979
28,542
454,608
$
$
$
$
205,348
46,793
252,141
85,960
20,728
358,829
203,833
14,027
217,860
78,703
16,764
313,327
$
136,087
13,734
149,821
65,428
9,350
224,599
$
$
$
$
$
$
$
$
$
39,222
-
39,222
-
-
39,222
26,557
-
26,557
-
-
26,557
30,661
-
30,661
-
-
30,661
$
$
$
$
37,987
-
37,987
-
10,523
48,510
11,655
-
11,655
-
7,010
18,665
12,244
259
12,503
-
6,562
19,065
$
$
$
$
7,712
-
7,712
-
-
7,712
9,066
-
9,066
-
-
9,066
8,504
-
8,504
-
-
8,504
$
$
$
$
23,978
314
24,292
22,322
1,634
48,248
17,510
158
17,668
23,019
804
41,491
16,337
34
16,371
13,275
852
30,498
$
$
$
$
(1) Oil and gas operating costs include labor, fuel, repairs, replacements, saltwater disposal and other related lifting
costs.
(2) Other international includes Ecuador, China and Argentina.
Oil and gas operating costs increased $29 million, or 11%, from 2006 to 2007. The increase is primarily the result of
expanded operations in Equatorial Guinea and the North Sea.
Oil and gas operating costs increased $66 million, or 33%, from 2005 to 2006 primarily as a result of our expanded
operations. Three new deepwater Gulf of Mexico development projects came online between December 2005 and
April 2006. Fiscal year 2006 represented a full year of Patina operations, and we acquired U.S. Exploration in 2006.
In addition, the high commodity price environment resulted in higher service, contract labor and fuel costs.
Insurance costs were also higher in 2006 due in part to increased rates for property damage coverage combined with
the added costs of providing business interruption coverage on deepwater Gulf of Mexico assets.
Workover and repair expense decreased $24 million during 2007 as compared with 2006. The decrease was
primarily due to a reduction in hurricane-related repair expense, which totaled $30 million in 2006 and $1 million in
2007.
Workover and repair expense increased $33 million during 2006 as compared with 2005. Expense for 2006 included
$30 million ($0.45 per BOE) of hurricane-related repair expense.
44
Production and ad valorem tax expense increased $5 million, or 4%, during 2007 as compared with 2006 and
increased $30 million, or 38%, during 2006 as compared with 2005. The increase reflects additional production from
U.S. Exploration and Patina properties. These properties have proportionately more production subject to such taxes.
Transportation expense increased $23 million, or 81%, during 2007 as compared with 2006. The increase was due
primarily due to changes in the terms of certain sales contracts for Northern region production and increased
production in the North Sea. Transportation expense increased $12 million, or 70%, during 2006 as compared with
2005. The increase was primarily due to a full year of Patina operations and U.S. Exploration.
Selected expenses on a per BOE of sales volume basis were as follows:
Oil and gas operating costs
Workover and repair expense
Lease operating costs
Production and ad valorem taxes
Transportation expense
Total production costs (1) (2)
2007
$
Year Ended December 31,
2006
$
2005
$
4.29
0.33
4.62
1.63
0.74
4.14
0.72
4.86
1.67
0.44
3.94
0.27
4.21
1.52
0.33
$
6.99
$
6.97
$
6.06
(1) Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
(2) Sales volumes include natural gas sales to an LNG facility in Equatorial Guinea that began late first quarter of
2007. The inclusion of these volumes reduced the unit rate by $0.51 per BOE for 2007.
The unit rates of total production costs per BOE, converting gas to oil on the basis of six Mcf per barrel, have been
increasing year-over-year since 2005. The increases are due to rising third-party costs, including insurance,
hurricane-related repair expense, and higher production taxes.
45
Oil and Gas Exploration Expense—Exploration expense was as follows:
Total
United
States
West
Africa
North
Sea
Other Int'l/
Corporate (1)
Israel
(in thousands)
Year Ended December 31, 2007
Dry hole expense
Unproved lease amortization
Seismic
Staff expense
Other
Total exploration expense
Year Ended December 31, 2006
Dry hole expense
Unproved lease amortization
Seismic
Staff expense
Other
Total exploration expense
Year Ended December 31, 2005
Dry hole expense
Unproved lease amortization
Seismic
Staff expense
Other
Total exploration expense
$
$
$
90,210
16,013
64,856
45,030
2,973
219,082
70,325
18,836
37,676
38,861
2,226
167,924
98,015
17,855
21,761
34,945
5,850
178,426
$
$
49,473
15,176
55,258
11,900
2,423
134,230
$
$
$
40,399
-
939
2,106
100
43,544
5
$
103
8,184
8,318
340
16,950
$
$
$
$
$
$
66,150
18,823
29,320
12,710
1,083
128,086
95,678
17,855
11,631
16,255
4,974
146,393
$
$
46
-
4,204
2,887
192
7,329
1,403
-
316
3,760
(16)
5,463
$
$
4,129
13
685
4,816
879
10,522
932
-
1,544
2,690
819
5,985
-
$
-
691
645
82
1,418
$
-
$
-
3
250
33
286
$
2
$
-
-
189
32
223
$
$
333
734
(216)
22,061
28
22,940
$
-
$
-
3,464
18,198
39
21,701
$
-
$
-
8,270
12,051
41
20,362
$
$
$
$
$
(1) Other international includes Ecuador, China, Argentina and Suriname.
Exploration expense increased $51 million, or 30% during 2007 as compared with 2006. US dry hole expense
decreased $17 million due to a reduction in the number of dry holes drilled during 2007. Dry hole expense increased
$40 million in West Africa and included amounts related to a dry exploratory well in Equatorial Guinea and expense
related to a secondary target of an exploration well in Cameroon in which commercial hydrocarbons were not found.
Seismic expense increased a net $27 million during 2007 as compared with 2006, primarily due to increases in US
seismic expense incurred in support of the 2007 Central Gulf of Mexico Outer Continental Shelf Sale. Staff expense
increased a net $6 million primarily due to new venture activity.
Exploration expense decreased $11 million, or 6% during 2006 as compared with 2005. US dry hole expense was
$30 million less due to the reduction in the number of dry holes drilled. US seismic expense increased $18 million
due primarily to the expansion of our deepwater Gulf of Mexico 3D seismic database. In addition, other
international staff expense increased $6 million due to new venture activity.
Exploration expense included stock-based compensation expense of $2 million in 2007 and $1 million in 2006.
46
Depreciation, Depletion and Amortization Expense—DD&A expense was as follows:
United States
West Africa
North Sea
Israel
Other international, corporate, and other
Total DD&A expense
Unit rate of DD&A per BOE (1) (2)
2007
Year Ended December 31,
2006
(in thousands)
$
543,431
23,620
8,123
13,947
33,487
622,608
$
574,001
25,315
79,450
17,842
31,373
727,981
$
$
2005
$
311,153
27,121
9,888
11,188
31,194
390,544
$
$
10.43
$
9.54
$
7.55
(1) Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
(2) Sales volumes include natural gas sales to an LNG facility in Equatorial Guinea that began late first quarter of
2007. The inclusion of these volumes reduced the unit rate by $0.62 per BOE for 2007.
Total DD&A expense has been increasing since 2005 primarily due to higher production volumes. The increase in
the unit rate for 2007 as compared with 2006 was primarily due to higher acquisition and development costs in the
the US and the Dumbarton North Sea development. The increase in the unit rate for 2006 as compared with 2005
was primarily due to the change in the mix of our production volumes, in particular, deepwater Gulf of Mexico
production.
DD&A expense includes abandoned assets cost of $5 million in 2007, $1 million in 2006 and $11 million in 2005.
General and Administrative Expense—General and administrative (“G&A”) expense was as follows:
Year Ended December 31,
2006
2005
2007
General and administrative expense (in thousands)
Unit rate per BOE (1) (2)
$
206,378
$
164,541
$
100,125
$
2.96
$
2.52
$
1.94
(1) Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
(2) Sales volumes include natural gas sales to an LNG facility in Equatorial Guinea that began late first quarter of
2007. The inclusion of these volumes reduced the unit rate by $0.21 per BOE for 2007.
G&A expense increased $42 million, or 25%, during 2007 as compared with 2006 due to higher salaries and wages,
including incentive compensation programs, resulting from an increase in the number of employees and results
exceeding targeted performance goals. In addition, the effects of adoption of SFAS No. 123(R), “Share-Based
Payment” (“SFAS 123(R)”), combined with additional equity-based awards, resulted in a $14 million increase in
stock-based compensation expense included in G&A during 2007. Stock-based compensation expense included in
G&A totaled $25 million in 2007.
G&A expense increased $64 million, or 64% during 2006 as compared with 2005. The increase was due to higher
salaries and wages and the inclusion of a full year of G&A expense related to Patina operations. Salaries and wages
also reflected wage inflation due to a tight labor market and expanded activity across the industry driven by higher
commodity prices. In addition, the effects of adoption of SFAS 123(R), combined with additional equity-based
awards, resulted in a $7 million increase in stock-based compensation expense included in G&A during 2006.
Stock-based compensation expense included in G&A was $11 million in 2006 as compared with $4 million in 2005.
G&A includes actuarially-computed net periodic benefit cost related to pension and other postretirement benefit
plans of $17 million in 2007, $19 million in 2006 and $11 million in 2005.
47
Interest Expense and Capitalized Interest—Interest expense and capitalized interest were as follows:
Interest expense, net
Capitalized interest
2007
$
112,957
16,595
Year Ended December 31,
2006
(in thousands)
$
117,045
12,515
2005
$
87,541
8,684
Interest expense, net of capitalized interest, decreased in 2007 primarily due to a declining rate of interest applicable
to the Credit Facility from 5.69% at December 31, 2006 to 5.28% at December 31, 2007. Interest expense, net of
capitalized interest, increased in 2006 due to additional borrowings related to the Patina Merger and acquisition of
U.S. Exploration and to increases in the interest rate applicable to the Credit Facility from 4.82% at December 31,
2005 to 5.69% at December 31, 2006.
Interest is capitalized on development projects using an interest rate equivalent to the average rate paid on long-term
debt. Capitalized interest is included in the cost of oil and gas assets and amortized with other costs on a unit-of-
production basis. The majority of the capitalized interest related to long lead-time projects in West Africa, the North
Sea and deepwater Gulf of Mexico in 2007; the North Sea and deepwater Gulf of Mexico in 2006; and deepwater
Gulf of Mexico and projects in West Africa in 2005.
We occasionally enter into forward contracts or swap agreements to hedge exposure to interest rate risk. At
December 31, 2007, AOCL included a deferred loss of $4 million, net of tax, related to interest rate swaps. $3
million of this amount is being reclassified into earnings, at the rate of $0.8 million per year, as an adjustment to
interest expense over the term of our 5¼% senior notes due 2014. The remaining $1 million loss relates to interest
rate locks that will expire in third quarter 2008. See Item 8. Financial Statements and Supplementary Data—Note
12—Derivative Instruments and Hedging Activities.
(Gain) Loss on Derivative Instruments—See Item 8. Financial Statements and Supplementary Data—Note 12—
Derivative Instruments and Hedging Activities.
Gain on Sale of Assets—See Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and
Divestitures.
Loss on Involuntary Conversion—See Item 8. Financial Statements and Supplementary Data—Note 4—Effect of
Gulf Coast Hurricanes.
Electricity Sales—Ecuador Integrated Power Project—Through our subsidiaries, EDC Ecuador Ltd. and
MachalaPower Cia. Ltda., we have a 100% ownership interest in an integrated natural gas-to-power project. The
project includes the Amistad natural gas field, offshore Ecuador, which supplies fuel to the Machala power plant.
Electricity sales are included in other revenues and electricity generation expense is included in other expense, net in
the consolidated statements of operations.
Operating data is as follows:
Electricity sales (in thousands)
Electricity generation expense (in thousands)
Operating income (in thousands)
Power generation (MW)
Average power price ($/Kwh)
Year Ended December 31,
2006
2005
2007
$
70,916
56,552
14,364
911,830
$
0.078
$
71,603
59,494
12,109
865,983
$
0.083
$
74,228
53,137
21,091
799,160
$
0.093
The volume of natural gas produced and electric power generated in Ecuador are related to thermal electricity
demand in Ecuador which typically declines at the onset of the rainy season. When Ecuador has sufficient rainfall to
allow hydroelectric power producers to provide base load power, we provide electricity only to meet peak demand.
As seasonal rains subside, we experience increasing demand for thermal electricity.
Electricity generation expense includes net increases in the allowance for doubtful accounts of $14 million in 2007,
$15 million in 2006 and $11 million in 2005. These increases have been made to cover potentially uncollectible
48
balances related to the Ecuador power operations. Certain entities purchasing electricity in Ecuador have been slow
to pay amounts due us. We are pursuing various strategies to protect our interests including international arbitration
and litigation.
Gathering, Marketing and Processing—We market a portion of our US natural gas production, as well as certain
third-party natural gas. We sell natural gas directly to end-users, natural gas marketers, industrial users, interstate
and intrastate pipelines, power generators and local distribution companies. We also market certain third-party crude
oil. Gathering, marketing and processing (“GMP”) proceeds are included in other revenues and GMP expenses are
included in other expense, net in the consolidated statements of operations. Gross margin from GMP activities was
as follows:
Year Ended December 31,
2007
2006
(in thousands)
2005
GMP proceeds
GMP expenses
Gross margin
$
$
$
24,087
17,539
6,548
27,876
18,664
9,212
$
$
$
55,261
28,067
27,194
We employ derivative instruments in connection with purchases and sales of third-party production to lock in profits
or limit exposure to commodity price risk. Most of the purchases we make are on an index basis. However,
purchasers in the markets in which we sell often require fixed or NYMEX-related pricing. We record gains and
losses on these derivative instruments using mark-to-market accounting. Gains (losses) were de minimis for 2007,
2006 and 2005. GMP proceeds for 2005 includes a gain of $11 million for the sale of certain gas sales and
transportation contractual assets.
Deferred Compensation Expense—In connection with the Patina Merger, we acquired the assets and assumed the
liabilities related to a deferred compensation plan. The assets of the deferred compensation plan are held in a rabbi
trust and include shares of our common stock and mutual fund investments. At December 31, 2007, 45% of the
market value of the assets in the rabbi trust related to our common stock. Deferred compensation expense totaled
$34 million, $16 million and $15 million for 2007, 2006, and 2005, respectively. See Item 8. Financial Statements
and Supplementary Data—Note 11—Benefit Plans.
Impairment of Operating Assets—We recorded impairments of $4 million in 2007, $9 million in 2006 and
$5 million in 2005, primarily related to downward reserve revisions on proved US oil and gas properties and/or
adjustment of the carrying value of properties to their fair values. Impairment expense is included in other expense,
net in the consolidated statements of operations.
Income Taxes—The income tax provision was as follows:
Income tax provision (in thousands)
Effective rate
Year Ended December 31,
2006
2005
2007
$
423,697
31.0%
$
417,789
38.1%
$
322,940
33.3%
Several factors resulted in a decrease in our effective tax rate for 2007. The major factor was that, in 2006,
$100 million of goodwill write-off associated with the sale of the Gulf of Mexico shelf properties was not
deductible, which increased the rate for 2006. Other factors were an increase in deferred tax assets arising from
foreign tax credits, a decrease in the Chinese tax rate, and the realization of additional income from equity method
investees which is a favorable permanent difference in calculating the income tax expense.
Our effective tax rate increased significantly in 2006 from 2005 due to several factors. The most significant factor
was the nondeductible goodwill write-off of $100 million related to the sale of the Gulf of Mexico shelf properties
discussed in the preceding paragraph. The rate was also impacted by decreases in our US deferred tax assets arising
from future foreign tax credits due to changes in the limitation on our ability to claim foreign tax credits. In addition,
a change in UK tax law increased our UK tax expense in 2006. Offsetting these increases was a reduction in the
effective tax rate due to an increase in earnings from equity method investees, which is a favorable permanent
difference in calculating income tax expense.
49
The 2005 effective tax rate was impacted by our ability to claim a foreign tax credit for the income taxes paid by
foreign branch operations, as well as a benefit realized on the repatriation of foreign earnings under the American
Jobs Creation Act of 2004.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Commodity Price Risk
Derivative Instruments Held for Non-Trading Purposes—We are exposed to market risk in the normal course of
business operations. We believe that we are well positioned with our mix of crude oil and natural gas reserves to
take advantage of future price increases that may occur. However, the uncertainty of crude oil and natural gas prices
continues to impact the oil and gas industry. Due to the volatility of crude oil and natural gas prices, we have used
derivative instruments as a means of managing our exposure to commodity price changes.
At December 31, 2007, we had entered into variable to fixed price swaps, costless collars and basis swaps related to
crude oil and natural gas sales. See Item 8. Financial Statements and Supplementary Data—Note 12—Derivative
Instruments and Hedging Activities.
As of December 31, 2007, we had a net unrealized loss of $408 million (pre-tax) related to crude oil and natural gas
derivative instruments entered into for hedging purposes. A net unrealized loss of $255 million, net of tax, is
recorded in AOCL in the consolidated balance sheets. We will reclassify the loss to earnings as adjustments to
revenue when future sales occur.
Interest Rate Risk
We are exposed to interest rate risk related to our variable and fixed interest rate debt. As of December 31, 2007, we
had $1.9 billion (excluding unamortized discount) of long-term debt outstanding. Of this amount, $650 million was
fixed-rate debt with a weighted average interest rate of 6.92%. We believe that anticipated near term changes in
interest rates will not have a material effect on the fair value of our fixed-rate debt and will not expose us to the risk
of earnings or cash flow loss.
The remainder of our long-term debt, $1.2 billion at December 31, 2007, was variable-rate debt. We also had $25
million of current installment payments at December 31, 2007. Variable rate debt exposes us to the risk of earnings
or cash flow loss due to increases in market interest rates. We estimate that a hypothetical 25 basis point change in
the floating interest rates applicable to the December 31, 2007 balance of variable-rate debt would result in a change
in annual interest expense of approximately $3 million.
We occasionally enter into forward contracts or swap agreements to hedge exposure to interest rate risk. Changes in
fair value of interest rate swaps or interest rate “locks” used as cash flow hedges are reported in AOCL, to the extent
the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to
interest expense. At December 31, 2007, AOCL included $4 million, net of tax, related to interest rate locks. A
portion of this amount is being reclassified into earnings as adjustments to interest expense over the term of our
5¼% Senior Notes due April 2014. The remainder relates to interest rate locks that are scheduled to settle during
third quarter 2008. See Item 8. Financial Statements and Supplementary Data—Note 12—Derivative Instruments
and Hedging Activities.
We are also exposed to interest rate risk related to our short-term investments. As of December 31, 2007,
substantially all of our cash was invested in highly liquid, short-term investment-grade securities with original
maturities of three months or less at the time of purchase. A hypothetical 25 basis point change in the floating
interest rates applicable to the December 31, 2007 balance would result in a change in annual interest income of
approximately $2 million.
Foreign Currency Risk
We have not entered into foreign currency derivatives. The US dollar is considered the functional currency for each
of our international operations. Transactions that are completed in a foreign currency are remeasured into US dollars
and recorded in the financial statements at the prevailing currency exchange rates. We do not have any significant
monetary assets or liabilities denominated in a foreign currency other than our foreign deferred tax liabilities in
certain foreign tax jurisdictions. An increase in exchange rates between the US dollar and the currency of the foreign
tax jurisdiction in which these liabilities are located could result in the use of additional cash to settle these
liabilities. However, transaction gains or losses were not material in any of the periods presented. We do not believe
we are currently exposed to any material risk of loss on this basis. Such gains or losses are included in other
expense, net in the consolidated statements of operations.
50
Item 8.
Financial Statements and Supplementary Data.
INDEX TO FINANCIAL STATEMENTS
Consolidated Financial Statements of Noble Energy, Inc.
Management’s Report on Internal Control over Financial Reporting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Report of Independent Registered Public Accounting Firm (Financial Statements) . . . . . . . . . . . . . . . . . . . . .
Report of Independent Registered Public Accounting Firm (Internal Control Over Financial Reporting). . . .
Consolidated Balance Sheets as of December 31, 2007 and 2006. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Operations for each of the three years in the period ended December 31, 2007 .
Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2007.
52
53
54
55
56
57
Consolidated Statements of Shareholders’ Equity for each of the three years in the period ended
December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
58
Consolidated Statements of Comprehensive Income (Loss) for each of the three years in the period ended
December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Supplemental Oil and Gas Information (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
59
60
94
Supplemental Quarterly Financial Information (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
104
51
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting.
Our internal control over financial reporting is a process designed under the supervision of our Chief Executive
Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of consolidated financial statements for external purposes in accordance with accounting
principles generally accepted in the United States of America.
Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements.
Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or processes may
deteriorate.
As of December 31, 2007, our management assessed the effectiveness of our internal control over financial
reporting based on the criteria for effective internal control over financial reporting established in “Internal
Control—Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway
Commission. Based on the assessment, management determined that we maintained effective internal control over
financial reporting as of December 31, 2007, based on those criteria. Management included in its assessment of
internal control over financial reporting all consolidated entities.
KPMG LLP, the independent registered public accounting firm that audited our consolidated financial statements
included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of internal control
over financial reporting as of December 31, 2007 which is included herein.
Noble Energy, Inc.
52
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Noble Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Noble Energy, Inc. and subsidiaries as of
December 31, 2007 and 2006, and the related consolidated statements of operations, shareholders’ equity,
comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31,
2007. These consolidated financial statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not
audit the financial statements for the periods referred to below of the Alba Plant LLC (Alba) and the Atlantic
Methanol Production Company, LLC (AMPCO), the investments in which, as disclosed in Note 13 of the
consolidated financial statements are accounted for by the equity method of accounting. The Company’s investment
in Alba as of December 31, 2007 and 2006 was $142.5 million and $146.1 million, respectively, and the equity in
earnings in Alba was $128.1 million and $101.3 million for the years ended December 31, 2007 and 2006,
respectively. The equity in earnings for AMPCO was $54.9 million for the year ended December 31, 2005. The
financial statements of Alba as of December 31, 2007 and 2006 and for the years then ended and AMPCO for the
year ended December 31, 2005 were audited by other auditors whose reports have been furnished to us, and our
opinion, insofar as it relates to the amounts included for Alba and AMPCO, is based solely on the report of the other
auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits and the report of the other auditors provide a reasonable
basis for our opinion.
In our opinion, based on our audits and the reports of the other auditors, the consolidated financial statements
referred to above present fairly, in all material respects, the financial position of Noble Energy, Inc. and subsidiaries
as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the years in
the three-year period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 2 to the consolidated financial statements, effective January 1, 2006, the Company changed its
method of accounting for stock-based compensation. As also discussed in Note 2 to the consolidated financial
statements, effective December 31, 2006, the Company changed its method of accounting for defined benefit
pension and other postretirement plans.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States), Noble Energy, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria
established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO), and our report dated February 25, 2008 expressed an unqualified opinion on the
effectiveness of the Company’s internal control over financial reporting.
KPMG LLP
Houston, Texas
February 25, 2008
53
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Noble Energy, Inc.:
We have audited Noble Energy, Inc.’s internal control over financial reporting as of December 31, 2007, based on
criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). Noble Energy, Inc.’s management is responsible for
maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting, included in the accompanying Management’s Report on Internal Control over
Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial
reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether effective internal control over financial reporting was maintained in all material respects. Our audit included
obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness
exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed
risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We
believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. A company’s internal control over financial reporting
includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.
In our opinion, Noble Energy, Inc. maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States), the consolidated balance sheets of Noble Energy, Inc. and subsidiaries as of December 31, 2007 and 2006,
and the related consolidated statements of operations, shareholders’ equity, comprehensive income (loss), and cash
flows for each of the years in the three-year period ended December 31, 2007, and our report dated February 25,
2008 expressed an unqualified opinion on those consolidated financial statements.
KPMG LLP
Houston, Texas
February 25, 2008
54
Noble Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
(in thousands, except share amounts)
ASSETS
Current Assets
Cash and cash equivalents
Accounts receivable - trade, net
Deferred income taxes
Assets held for sale
Probable insurance claims
Other current assets
Total current assets
Property, plant and equipment
Oil and gas properties (successful efforts method of accounting)
Other property, plant and equipment
Accumulated depreciation, depletion and amortization
Total property, plant and equipment, net
Other noncurrent assets
Goodwill
Total Assets
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable - trade
Derivative instruments
Income taxes
Current installment of long-term debt
Asset retirement obligations
Other current liabilities
Total current liabilities
Deferred income taxes
Asset retirement obligations
Derivative instruments
Other noncurrent liabilities
Long-term debt
Total Liabilities
Commitments and Contingencies
December 31,
2007
2006
$
659,863
594,009
130,571
82,122
2,184
100,518
1,569,267
10,216,484
112,339
10,328,823
(2,384,359)
7,944,464
556,669
760,496
10,830,896
$
$
780,915
540,217
51,785
25,000
13,332
224,494
1,635,743
1,983,833
130,956
82,803
337,667
1,851,087
6,022,089
$
153,408
586,882
99,835
164
101,233
127,024
1,068,546
8,867,639
79,646
8,947,285
(1,776,528)
7,170,757
568,032
781,290
9,588,625
$
$
518,609
254,625
107,136
-
68,500
235,392
1,184,262
1,758,452
127,689
328,875
274,720
1,800,810
5,474,808
Shareholders’ Equity
Preferred stock - par value $1.00; 4,000,000 shares authorized,
none issued
Common stock - par value $3.33 1/3; 250,000,000 shares authorized;
190,814,309 and 188,808,087 shares issued, respectively
Capital in excess of par value
Accumulated other comprehensive loss
Treasury stock, at cost: 18,580,865 and 16,574,384 shares, respectively
Retained earnings
Total Shareholders’ Equity
Total Liabilities and Shareholders’ Equity
The accompanying notes are an integral part of these financial statements
-
-
636,046
2,105,895
(284,185)
(612,976)
2,964,027
4,808,807
10,830,896
$
629,360
2,041,048
(140,509)
(511,443)
2,095,361
4,113,817
9,588,625
$
55
Noble Energy, Inc. and Subsidiaries
Consolidated Statements of Operations
(in thousands, except per share amounts)
Revenues
Oil and gas sales
Income from equity method investees
Other revenues
Total Revenues
Costs and Expenses
Lease operating costs
Production and ad valorem taxes
Transportation expense
Exploration expense
Depreciation, depletion and amortization
General and administrative
Accretion of discount on asset retirement obligations
Interest, net of amount capitalized
(Gain) loss on derivative instruments
Gain on sale of assets
Loss on involuntary conversion
Other expense, net
Total Costs and Expenses
Income Before Taxes
Income Tax Provision
Net Income
Earnings Per Share
Basic
Diluted
Weighted average number of shares outstanding
Basic
Diluted
Year Ended December 31,
2006
2005
2007
$
2,966,099
210,928
95,003
3,272,030
$
2,701,241
139,362
99,479
2,940,082
$
1,966,422
90,812
129,489
2,186,723
322,452
113,547
51,699
219,082
727,981
206,378
8,125
112,957
(2,520)
(11,854)
51,406
105,210
1,904,463
317,087
108,979
28,542
167,924
622,608
164,541
10,797
117,045
392,367
(219,577)
-
133,552
1,843,865
217,860
78,703
16,764
178,426
390,544
100,125
11,214
87,541
32,680
(4,201)
1,000
107,407
1,218,063
1,367,567
423,697
943,870
$
1,096,217
417,789
678,428
$
968,660
322,940
645,720
$
$
$
5.52
5.45
$
$
3.86
3.79
$
$
4.20
4.12
171,078
173,344
175,707
179,044
153,773
156,759
The accompanying notes are an integral part of these financial statements
56
Noble Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(in thousands)
Cash Flows from Operating Activities
Net income
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization - oil and gas production
Depreciation, depletion and amortization - electricity generation
Dry hole expense
Impairment of operating assets
Amortization of unproved leasehold costs
Stock-based compensation expense
Gain on sale of assets
Deferred income taxes
Accretion of discount on asset retirement obligations
Increase in allowance for doubtful accounts
Income from equity method investees
Dividends from equity method investees
Deferred compensation expense
Non-cash (gain) loss on derivative instruments
Loss on involuntary conversion
Other
Changes in operating assets and liabilities, net of acquisition:
Increase in accounts receivable
Decrease (increase) in other current assets
Decrease (increase) in probable insurance claims
Increase (decrease) in accounts payable
Decrease in other current liabilities
Net Cash Provided by Operating Activities
Cash Flows From Investing Activities
Additions to property, plant and equipment
Acquisition of U.S. Exploration, net of cash acquired
Acquisiton of Patina, net of cash acquired
Proceeds from sale of property, plant and equipment
Investments in equity method investees
Distributions from equity method investees
Net Cash Used in Investing Activities
Cash Flows From Financing Activities
Exercise of stock options
Excess tax benefits from stock-based awards
Cash dividends paid
Purchase of treasury stock
Proceeds from credit facilities
Repayment of credit facilities
Repayment of term loans
Repayment of Patina debt
Net Cash Provided by (Used in) Financing Activities
Increase (Decrease) in Cash and Cash Equivalents
Cash and Cash Equivalents at Beginning of Period
Cash and Cash Equivalents at End of Period
Year Ended December 31,
2006
2007
2005
$
943,870
$
678,428
$
645,720
727,981
14,277
90,210
3,661
16,013
26,825
(11,854)
291,881
8,125
15,272
(210,928)
226,634
33,526
(184,944)
51,406
(1,733)
(21,609)
8,048
108,075
19,278
(137,441)
2,016,573
(1,414,515)
-
-
9,326
-
2,100
(1,403,089)
24,636
20,072
(75,204)
(101,533)
280,000
(255,000)
-
-
(107,029)
506,455
153,408
659,863
$
622,608
16,319
70,325
8,525
18,923
11,816
(219,577)
194,261
10,797
15,891
(139,362)
37,350
15,936
415,298
-
21,509
(32,348)
(4,954)
139,590
(11,151)
(139,878)
1,730,306
(1,357,039)
(412,257)
-
519,567
(3,768)
155,158
(1,098,339)
62,613
26,106
(48,924)
(398,675)
480,000
(605,000)
(105,000)
-
(588,880)
43,087
110,321
153,408
$
390,544
16,476
98,015
5,368
17,855
3,467
(4,201)
183,770
11,214
5,551
(90,812)
59,625
14,980
32,680
1,000
(40,421)
(73,940)
(28,254)
(25,306)
20,747
(4,200)
1,239,878
(785,610)
-
(1,111,099)
13,179
(13,927)
4,969
(1,892,488)
67,657
-
(23,655)
-
3,335,333
(2,140,333)
(45,000)
(610,865)
583,137
(69,473)
179,794
110,321
$
The accompanying notes are an integral part of these financial statements
57
Noble Energy, Inc. and Subsidiaries
Consolidated Statements of Shareholders' Equity
(in thousands)
$
Common
Stock
417,152
-
185,568
13,013
Capital in
Excess of
Par Value
$
291,458
-
1,576,799
54,644
Deferred
Compensation -
Restricted
Stock
$
(1,671)
-
-
-
Accumulated
Other
Comprehensive
Loss
Treasury
Stock
at Cost
Retained
Earnings
$
(14,787)
-
-
-
$
(75,956)
-
(73,203)
-
$
843,792
645,720
-
-
$
Total
Shareholders'
Equity
1,459,988
645,720
1,689,164
67,657
-
578
-
-
-
-
-
-
-
-
15,407
6,506
-
-
90
335
-
-
-
-
616,311
1,945,239
-
-
-
12,829
-
220
-
-
-
-
-
-
-
-
(5,288)
11,816
49,784
26,106
(220)
-
-
13,611
-
-
-
-
-
629,360
-
2,041,048
-
-
4,930
-
1,756
-
-
-
-
-
-
26,825
19,706
20,072
(1,756)
-
-
-
-
-
-
(7,084)
3,467
-
-
-
-
-
-
-
(5,288)
-
5,288
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
$
636,046
$
2,105,895
$
-
-
-
-
-
-
-
154,500
33,638
(945,033)
(11,817)
(768,712)
(783,499)
-
-
-
-
-
-
-
-
-
145,035
264,520
249,974
16,862
676,391
(33,401)
(140,509)
-
-
-
-
-
-
-
33,761
(184,254)
6,817
(143,676)
(284,185)
$
-
-
-
-
683
-
-
-
-
-
-
-
-
(23,655)
-
-
-
-
-
-
15,407
-
3,467
(23,655)
773
335
154,500
33,638
(945,033)
(11,817)
(148,476)
1,465,857
3,090,144
-
-
-
-
-
-
-
(398,675)
35,708
-
-
-
-
-
(511,443)
-
-
-
-
-
-
(101,533)
-
-
-
678,428
-
-
-
-
-
(48,924)
-
-
-
-
-
-
-
2,095,361
943,870
-
-
-
-
(75,204)
-
678,428
-
11,816
62,613
26,106
-
(48,924)
(398,675)
49,319
145,035
264,520
249,974
16,862
(33,401)
4,113,817
943,870
26,825
24,636
20,072
-
(75,204)
(101,533)
-
-
-
33,761
(184,254)
6,817
$
(612,976)
$
2,964,027
$
4,808,807
December 31, 2004
Net income
Patina Merger
Exercise of stock options
Tax benefits related to
exercise of stock options
Restricted stock awards, net
Amortization of restricted stock
Cash dividends ($0.15 per share)
Rabbi trust shares sold
Other
Oil and gas cash flow hedges:
Realized amounts
reclassified into earnings
Unrealized amounts
reclassified into earnings
Unrealized change in fair value
Net change in other
Other comprehensive loss
December 31, 2005
Net income
Adoption of SFAS 123(R), net of tax
Stock-based compensation expense
Exercise of stock options
Tax benefits related to
exercise of stock options
Restricted stock awards, net
Cash dividends ($0.275 per share)
Purchase of treasury stock
Rabbi trust shares sold
Oil and gas cash flow hedges:
Realized amounts
reclassified into earnings
Unrealized amounts
reclassified into earnings
Unrealized change in fair value
Net change in other
Other comprehensive income
Adoption of SFAS 158, net of tax
December 31, 2006
Net income
Stock-based compensation expense
Exercise of stock options
Tax benefits related to
exercise of stock options
Restricted stock awards, net
Cash dividends ($0.435 per share)
Purchase of treasury stock
Oil and gas cash flow hedges:
Realized amounts
reclassified into earnings
Unrealized change in fair value
Net change in other
Other comprehensive loss
December 31, 2007
The accompanying notes are an integral part of these financial statements
58
Noble Energy, Inc. and Subsidiaries
Consolidated Statements of Comprehensive Income (Loss)
(in thousands)
Net income
Other items of comprehensive income (loss)
Oil and gas cash flow hedges:
Realized amounts reclassified into earnings
Less tax provision
Unrealized amounts reclassified into earnings
Less tax provision
Unrealized change in fair value
Less tax provision
Interest rate cash flow hedges:
Realized amounts reclassified into earnings
Less tax provision
Unrealized change in fair value
Less tax provision
Net change in other
Less tax provision
Year Ended December 31,
2006
2005
2007
$
943,870
$
678,428
$
645,720
54,105
(20,344)
-
-
(295,279)
111,025
758
(285)
(1,203)
452
11,369
(4,274)
232,428
(87,393)
423,910
(159,390)
351,637
(101,663)
758
(121)
-
-
25,002
(8,777)
237,692
(83,192)
51,750
(18,112)
(1,453,897)
508,864
757
(265)
-
-
(18,937)
6,628
Other comprehensive income (loss)
(143,676)
676,391
(768,712)
Comprehensive income (loss)
$
800,194
$
1,354,819
$
(122,992)
The accompanying notes are an integral part of these financial statements
59
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollar amounts in tables, unless otherwise indicated, are in thousands, except per share amounts)
Note 1—Nature of Operations
Noble Energy, Inc. (“Noble Energy”, “we” or “us”) is an independent energy company engaged in the acquisition,
exploration, development, production and marketing of crude oil and natural gas. We have exploration, exploitation
and production operations domestically and internationally. We operate throughout major basins in the US including
Colorado’s Wattenberg field and Piceance basin, the Mid-continent area of western Oklahoma and the Texas
Panhandle, the San Juan basin in New Mexico, the Gulf Coast and the deepwater Gulf of Mexico. In addition, we
conduct business internationally in China, Ecuador, the Mediterranean Sea, the North Sea, West Africa (Equatorial
Guinea and Cameroon) and in other areas. In 2005, we merged with Patina Oil & Gas Corporation (“Patina”) and in
2006 we acquired U.S. Exploration Holdings, Inc. (“U.S. Exploration”).
Note 2—Summary of Significant Accounting Policies
Basis of Presentation and Consolidation—Accounting policies used by us and our subsidiaries conform to
accounting principles generally accepted in the US. Significant policies are discussed below. Our consolidated
accounts include our accounts and the accounts of our wholly-owned subsidiaries. We use the equity method of
accounting for investments in entities that we do not control but over which we exert significant influence. We carry
equity method investments at our share of net assets of the equity investees plus our loans and advances. Differences
in the basis of the investment and the separate net asset value of the investee, if any, are amortized into income over
the remaining useful life of the underlying assets. All significant intercompany balances and transactions have been
eliminated upon consolidation.
Use of Estimates—The preparation of consolidated financial statements in conformity with accounting principles
generally accepted in the US (GAAP) requires us to make a number of estimates and assumptions relating to the
reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the
consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.
Estimates of crude oil and natural gas reserves are the most significant of our estimates. All of the reserve data in
this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground
accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of
proved crude oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be
different from the quantities of crude oil and natural gas that are ultimately recovered. Engineers in our Houston,
Denver and London offices prepare all reserve estimates for our different geographical regions. These reserve
estimates are reviewed and approved by senior engineering staff and division management with final approval by
the Director of Asset Development and certain members of senior management. See Supplemental Oil and Gas
Information.
Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment and
goodwill, asset retirement obligations, valuation allowances for receivables and deferred income tax assets,
valuation of derivative instruments, and obligations related to employee benefits. Actual results could differ
significantly from those estimates.
Foreign Currency—The US dollar is considered the functional currency for each of our international operations.
Transactions that are completed in foreign currencies are remeasured into US dollars and recorded in the financial
statements at prevailing foreign exchange rates. Transaction gains or losses were not material in any of the periods
presented and are included in other expense, net on the statements of operations.
Allowance for Doubtful Accounts—We routinely assess the recoverability of all material trade and other receivables
to determine their collectibility. We accrue a reserve on a receivable when, based on management’s judgment, it is
probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated.
60
Changes in the allowance for doubtful accounts are as follows:
2007
Year Ended December 31,
2006
(in thousands)
2005
Balance at beginning of period
Charged to expense
Deductions and other
Balance at end of period
$
$
$
34,535
14,183
1,089
49,807
18,644
19,404
(3,513)
34,535
13,093
14,688
(9,137)
18,644
$
$
$
Amounts charged to expense include $14 million in 2007, $15 million in 2006 and $11 million in 2005 to cover
potentially uncollectible balances related to Ecuador power operations. These amounts are included in electricity
generation expense. Certain entities purchasing electricity in Ecuador have been slow to pay amounts due us. We are
pursuing various strategies to protect our interests including international arbitration and litigation. The allowance
was also increased by $2 million in 2006 and $1 million in 2005 to record various provisions related to our US
business. In addition, in 2005 the allowance was decreased due to the final write-off of certain allowances recorded
in prior years ($6 million).
Materials and Supplies Inventories—Materials and supplies inventories, consisting principally of tubular goods and
production equipment, are stated at the lower of cost or market.
Property, Plant and Equipment—
Successful Efforts Method—We account for crude oil and natural gas properties under the successful efforts method
of accounting. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, to drill
and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized.
Capitalized costs of producing crude oil and natural gas properties are amortized to operations by the unit-of-
production method based on proved crude oil and natural gas reserves on a property-by-property basis as estimated
by our engineers. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated
DD&A are eliminated from the accounts and the resulting gain or loss is recognized. Repairs and maintenance are
expensed as incurred.
Proved Property Impairment—In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of
Long-Lived Assets,” we review proved oil and gas properties and other long-lived assets for impairment when
events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a
downward revision of the reserve estimates or sustained decrease in commodity prices. We estimate the future cash
flows expected in connection with the properties and compare such future cash flows to the carrying amount of the
properties to determine if the carrying amount is recoverable. When the carrying amounts of the properties exceed
their estimated undiscounted future cash flows, the carrying amount of the properties is reduced to their estimated
fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves,
future commodity prices and operating expenses, timing of future production, future capital expenditures and a risk-
adjusted discount rate. We recorded impairments of approximately $4 million in 2007, $9 million in 2006 and
$5 million in 2005, primarily related to downward reserve revisions on US properties and/or adjustment of the
carrying value of properties to their fair values.
Unproved Property Impairment—We also periodically assess individually significant unproved properties for
impairment of value and recognize a loss at the time of impairment by providing an impairment allowance. Cash
flows used in the impairment analysis are determined based on management’s estimates of crude oil and natural gas
reserves, future commodity prices and future costs to extract the reserves. Cash flow estimates related to probable
and possible reserves are reduced by additional risk-weighting factors. Other individually insignificant unproved
properties are amortized on a composite method based on our experience of successful drilling and average holding
period. We recorded impairments of individually significant unproved properties of approximately $3 million in
2007, $1 million in 2006, and $3 million in 2005 and included the amounts in exploration expense.
Properties Acquired in Business Combinations—In determining the fair values of proved and unproved properties
acquired in business combinations, we prepare estimates of crude oil and natural gas reserves. We estimate future
prices to apply to the estimated reserve quantities acquired, and estimate future operating and development costs, to
arrive at estimates of future net cash flows. For the fair value assigned to proved reserves, the future net cash flows
are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the
61
business combination. To compensate for the inherent risk of estimating and valuing unproved reserves, the
discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors.
Exploration Costs—Geological and geophysical costs, delay rentals, amortization of unproved leasehold costs, and
costs to drill exploratory wells that do not find proved reserves are expensed as oil and gas exploration. We carry the
costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as
a producing well and as long as we are making sufficient progress assessing the reserves and the economic and
operating viability of the project. For certain capital-intensive deepwater Gulf of Mexico or international projects, it
may take us more than one year to evaluate the future potential of the exploration well and make a determination of
its economic viability. Our ability to move forward on a project may be dependent on gaining access to
transportation or processing facilities or obtaining permits and government or partner approval, the timing of which
is beyond our control. In such cases, exploratory well costs remain suspended as long as we are actively pursuing
access to necessary facilities and access to such permits and approvals and believe they will be obtained. We assess
the status of suspended exploratory well costs on a quarterly basis. See Note 5—Capitalized Exploratory Well Costs.
Other Property—Other property includes autos, trucks, airplane, office furniture and computer equipment and other
fixed assets. These items are recorded at cost and are depreciated on the straight-line method based on expected lives
of the individual assets or group of assets, which range from three to seven years.
Balance Sheet Information—Additional balance sheet information is as follows:
December 31,
2007
2006
(in thousands)
$
$
$
$
$
$
$
$
15,058
60,479
24,981
100,518
357,129
123,779
37,475
4,829
33,457
556,669
206,435
18,059
224,494
225,098
50,972
61,597
337,667
$
$
$
$
$
$
35,242
46,973
44,809
127,024
373,372
116,314
46,500
2,862
28,984
568,032
219,885
15,507
235,392
173,253
58,491
42,976
274,720
$
$
Other Current Assets
Derivative instruments
Materials and supplies inventories
Prepaid expenses and other
Total
Other Noncurrent Assets
Equity method investments
Mutual fund investments
Probable insurance claims
Derivative instruments
Other assets
Total
Other Current Liabilities
Accrued and other current liabilities
Interest payable
Total
Other Noncurrent Liabilities
Deferred compensation liabilities
Accrued benefit costs
Other noncurrent liabilities
Total
62
Statement of Operations Information—Other revenues and other expense, net consist of the following:
2007
Year Ended December 31,
2006
(in thousands)
2005
Other Revenues
Electricity sales
Gathering, marketing and processing
Total
Other Expense, net
Electricity generation (1)
Gathering, marketing and processing
Deferred compensation expense
Impairment of operating assets
Other
Total
(1) See Allowance for Doubtful Accounts above.
$
$
70,916
24,087
95,003
$
$
71,603
27,876
99,479
$
$
74,228
55,261
129,489
$
$
$
56,552
17,539
33,526
3,661
(6,068)
105,210
59,494
18,664
15,936
8,525
30,933
133,552
$
$
$
53,137
28,067
14,980
5,368
5,855
107,407
Supplementary Disclosures of Cash Flow Information—Additional cash flow information is as follows:
Cash paid during the year for:
Interest (net of amount capitalized)
Income taxes paid, net
Non-cash financing and investing activities:
Issuance of notes for property interests
Issuance of common stock and options
and liabilities assumed in Patina Merger
2007
Year Ended December 31,
2006
(in thousands)
2005
$
104,910
149,058
$
105,769
115,398
$
83,860
121,687
50,000
-
-
-
-
3,783,306
Goodwill—Goodwill represents the excess of the cost of an acquired entity over the net amounts assigned to assets
acquired and liabilities assumed. We account for goodwill in accordance with SFAS No. 142, “Goodwill and Other
Intangible Assets” (“SFAS 142”). Goodwill is not amortized to earnings but is tested annually during the fourth
quarter or whenever events or changes in circumstances indicate that the carrying value may not be recoverable. No
goodwill impairment was indicated as of December 31, 2007. Changes in the carrying amount of goodwill are as
follows:
Year Ended December 31,
2007
2006
(in thousands)
Balance at beginning of period
Goodwill associated with acquisitions
Goodwill associated with sale of Gulf of Mexico shelf properties
Tax benefits on stock options exercised
Balance at end of period
$
$
781,290
(15,091)
-
(5,703)
760,496
862,868
27,711
(100,000)
(9,289)
781,290
$
$
In accordance with Emerging Issues Task Force (“EITF”) Abstract Issue No. 00-23, “Issues Related to the
Accounting for Stock Compensation under APB Opinion No. 25 and FASB Interpretation No. 44”, we reduce the
amount of goodwill originally recorded for deferred tax assets associated with the exercise of fully-vested stock
options assumed in conjunction with the Patina Merger to the extent that the stock-based compensation expense
reported for tax purposes does not exceed the fair value of the awards recognized as part of the total purchase price.
63
Income Taxes—Income taxes are accounted for under the asset and liability method. Deferred tax assets and
liabilities are recognized when items of income and expense are recognized in the financial statements in different
periods than when recognized in the tax return. Deferred tax assets arise when expenses are recognized in the
financial statements before the tax returns or when income items are recognized in the tax return prior to the
financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax
payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial
statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements.
Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the
years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets
and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in
the tax rate was passed.
Fair Value of Financial Instruments—The following methods and assumptions were used to estimate the fair values
for each class of financial instruments. The fair value of a financial instrument is the amount at which the instrument
could be exchanged in a current transaction between two willing parties.
Cash, Cash Equivalents, Accounts Receivable and Accounts Payable—The carrying amounts approximate fair value
due to the short-term nature or maturity of the instruments.
Mutual Funds—The fair value is based on published market prices.
Debt—The fair value of debt is estimated based on the published market prices for the same or similar issues. The
carrying amounts and estimated fair values of debt instruments are as follows:
December 31,
2007
2006
Carrying Amount
Fair Value
Carrying Amount
Fair Value
(in thousands)
Total debt, net of discount
$
1,876,087
$
1,919,990
$
1,800,810
$
1,852,890
See Note 7—Debt.
Derivative Instruments—The fair value estimates for commodity fixed price swaps, basis swaps and costless collars use
published market prices for the underlying commodities and discount rates to determine discounted expected future
cash flows as of the date of the estimate. See Note 12—Derivative Instruments and Hedging Activities.
Capitalization of Interest—We capitalize interest costs associated with the development and construction of
significant properties or projects to bring them to a condition and location necessary for their intended use, which for
crude oil and natural gas assets is at first production from the field. Interest is capitalized using an interest rate
equivalent to the average rate we pay on long-term debt, including the credit facility and bonds. Capitalized interest
is included in the cost of oil and gas assets and amortized with other costs on a unit-of-production basis. Capitalized
interest totaled $17 million in 2007, $13 million in 2006 and $9 million in 2005.
Statement of Cash Flows—For purposes of reporting cash flows, cash and cash equivalents include unrestricted cash
on hand and investments purchased with original maturities of three months or less.
Basic and Diluted Earnings Per Share—Basic earnings per share (“EPS”) of common stock have been computed on
the basis of the weighted average number of shares outstanding during each period. The diluted EPS of common
stock includes the effect of outstanding common stock equivalents.
64
The calculation of basic and diluted EPS is as follows:
Net income available to
common shareholders
Basic EPS
Net income available to
common shareholders
Effect of dilutive stock options
and restricted stock awards
Adjusted net income and shares
Diluted EPS
2007
Year Ended December 31,
2006
2005
Income
Shares
Income
Shares
Income
Shares
(in thousands, except per share amounts)
943,870
$
$ 5.52
171,078
$
$
678,428
3.86
175,707
$
$
645,720
4.20
153,773
$
943,870
171,078
$
678,428
175,707
$
645,720
153,773
-
943,870
5.45
$
$
2,266
173,344
-
678,428
3.79
$
$
3,337
179,044
-
645,720
4.12
$
$
2,986
156,759
Options, restricted stock and shares of our common stock held in a rabbi trust excluded from the EPS calculation
above as they were antidilutive are as follows:
Weighted Outstanding
Awards and Shares
Weighted Average
Exercise Price
(in thousands, except per share amounts)
Year Ended December 31, 2007
Stock options
Noble Energy common stock held
in rabbi trust and shares of restricted stock
Total excluded from diluted EPS calculation
Year Ended December 31, 2006
Stock options
Noble Energy common stock held
in rabbi trust and shares of restricted stock
Total excluded from diluted EPS calculation
Year Ended December 31, 2005
Stock options
Noble Energy common stock held in rabbi trust
Total excluded from diluted EPS calculation
1,014
1,102
2,116
675
1,276
1,951
48
1,360
1,408
$
52.41
-
-
$
45.19
-
-
$
41.47
-
Accounting for Uncertainty in Income Taxes – We adopted FASB Interpretation No. 48, “Accounting for
Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (“FIN 48”) as of January 1, 2007. FIN
48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in
accordance with SFAS No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a recognition threshold and
measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to
be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties,
accounting in interim periods, disclosure, and transition. We also adopted FASB Staff Position No. FIN 48-1,
“Definition of Settlement in FASB Interpretation No. 48” (“FSP FIN 48-1”) as of January 1, 2007. FSP FIN 48-1
provides that a company’s tax position will be considered settled if the taxing authority has completed its
examination, the company does not plan to appeal, and it is remote that the taxing authority would reexamine the tax
position in the future. The adoption of FIN 48 and FSP FIN 48-1 had no effect on our financial position or results of
operations. See Note 8—Income Taxes.
Accounting for Stock-Based Compensation—Through December 31, 2005, we accounted for stock-based
compensation plans under the intrinsic value recognition and measurement principles of APB Opinion No. 25,
“Accounting for Stock Issued to Employees” (“APB 25”), and related Interpretations. As of January 1, 2006, we
adopted SFAS No. 123(R), “Share-Based Payment” (“SFAS 123(R)”). SFAS 123(R) revised SFAS No. 123,
“Accounting for Stock-Based Compensation” and nullified APB 25 and its related implementation guidance.
65
SFAS 123(R) requires companies to measure the grant-date fair value of stock options and other stock-based
compensation issued to employees and expense the fair value over the requisite service period of the award.
SFAS 123(R) became effective for interim or annual periods beginning January 1, 2006. In accordance with the
modified prospective transition method, prior period amounts have not been restated. See Note 9—Stock-Based
Compensation.
Accounting for Defined Benefit Pension and Other Postretirement Plans—In September 2006, the Financial
Accounting Standards Board (the “FASB”) issued SFAS No. 158, “Employers’ Accounting for Defined Benefit
Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS
158”). SFAS 158 requires plan sponsors of defined benefit pension and other postretirement benefit plans to
recognize the funded status of their postretirement benefit plans in the statement of financial position, measure the
fair value of plan assets and benefit obligations as of the date of the fiscal year-end statement of financial position,
and provide additional disclosures. We adopted SFAS 158 as of December 31, 2006, and the effect of adoption on
our financial condition at December 31, 2006 was included in our consolidated balance sheets. Adoption of SFAS
158 had no effect on our results of operations for the year ended December 31, 2006. See Note 11—Benefit Plans.
Adoption of Staff Accounting Bulletin No. 108—In September 2006, the Securities and Exchange Commission
(“SEC”) issued Staff Accounting Bulletin No. 108 (“SAB 108”). SAB 108 expresses the SEC staff’s views
regarding the process of quantifying financial statement misstatements. The SEC staff believes registrants should
quantify errors using both a balance sheet and an income statement approach and evaluate whether either approach
results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is
material. SAB 108 is effective for fiscal years ending on or after November 15, 2006. We adopted SAB 108 as of
December 31, 2006. Adoption of SAB 108 had no effect on our financial position or results of operations.
Treasury Stock—We record treasury stock purchases at cost, which includes incremental direct transaction costs.
Amounts are recorded as reductions in shareholders’ equity.
Revenue Recognition and Imbalances—We record revenues from the sales of crude oil and natural gas when the
product is delivered at a fixed or determinable price, title has transferred and collectibility is reasonably assured.
When we have an interest with other producers in properties from which natural gas is produced, we use the
entitlements method to account for any imbalances. Imbalances occur when we sell more or less product than we are
entitled to under our ownership percentage. Revenue is recognized only on the entitlement percentage of volumes
sold. Any amount that we sell in excess of our entitlement is treated as a liability and is not recognized as revenue.
Any amount of entitlement in excess of the amount we sell is recognized as revenue and a receivable is accrued. We
record the noncurrent portion of the liability in other deferred credits and noncurrent liabilities, and the current
portion of the liability in other current liabilities. We record the noncurrent portion of the receivable in other assets
and the current portion of the receivable in other current assets. Imbalance liabilities were $10 million and
$17 million at December 31, 2007 and 2006, respectively. Imbalance receivables were $13 million and $18 million
at December 31, 2007 and 2006, respectively.
Revenues derived from electricity generation are recognized when power is transmitted or delivered, the price is
fixed and determinable and collectibility is reasonably assured.
We also engage in the purchase and sale of third-party crude oil and natural gas. We record third-party sales, net of
cost of goods sold, as gathering, marketing and processing revenues when the product is delivered or the contract is
net settled at a fixed or determinable price, title has transferred and collectibility is reasonably assured.
Derivative Instruments and Hedging Activities—We use various derivative instruments in connection with
anticipated crude oil and natural gas sales to minimize the impact of commodity price fluctuations. Such instruments
include variable to fixed NYMEX price swaps, costless collars and variable to fixed price basis swaps. We account
for derivative instruments and hedging activities in accordance with SFAS No. 133, “Accounting for Derivative
Instruments and Hedging Activities, as amended,” (“SFAS 133”). SFAS 133 established accounting and reporting
standards requiring every derivative instrument (including certain derivative instruments embedded in other
contracts) to be recorded on the balance sheet as either an asset or liability measured at fair value. SFAS 133
requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge
accounting criteria are met. Under cash flow hedge accounting, gains and losses are reflected in shareholders’ equity
as accumulated other comprehensive income or loss (“AOCL”) until the forecasted transaction occurs. The
derivative’s gains and losses are then offset against related results on the hedged transaction on the statements of
operations. Gains and losses from derivative instruments related to crude oil and natural gas sales and which qualify
66
for hedge accounting treatment are recorded in oil and gas sales in the consolidated statements of operations upon
sale of the associated commodity.
SFAS 133 also requires that a company formally document, designate and assess the effectiveness of transactions
that receive hedge accounting. Only derivative instruments that are expected to be highly effective in offsetting
anticipated gains or losses on the hedged cash flows and that are subsequently documented to have been highly
effective can qualify for hedge accounting. Effectiveness must be assessed both at inception of the hedge and on an
ongoing basis. Any ineffectiveness in hedging instruments whereby gains or losses do not exactly offset anticipated
gains or losses of hedged cash flows is measured and recognized in earnings in the period in which it occurs. We
assess hedge effectiveness quarterly based on total changes in the derivative’s fair value and using regression
analysis. A hedge is considered effective if certain statistical tests are met. We record hedge ineffectiveness in loss
on derivative instruments. See Note 12—Derivative Instruments and Hedging Activities.
Through December 31, 2007, we elected to designate the majority of our crude oil and natural gas derivative instruments as
cash flow hedges. Effective January 1, 2008, we discontinued cash flow hedge accounting on all existing commodity
derivative instruments. We voluntarily made this change to provide greater flexibility in our use of derivative
instruments. From January 1, 2008 forward, we will recognize all gains and losses on such instruments in earnings
in the period in which they occur. Net derivative losses that were deferred in AOCL as of December 31, 2007, will be
reclassified to earnings in future periods as the original hedged transactions affect earnings. The discontinuance of cash flow
hedge accounting for commodity derivative instruments did not affect our net assets or cash flows at December 31, 2007 and
does not require adjustments to our previously reported financial statements.
Related Party Transaction—We entered into a consulting agreement with a former officer of Patina who now serves
as a member of our Board of Directors. Pursuant to the consulting agreement, the Board member served as a
consultant to the combined company for a period of 12 months following the merger (May 16, 2005) in exchange
for a monthly retainer of $50,000. We paid total consulting fees of $225,806 during 2006 and $374,194 during 2005.
We also reimbursed his office space rent of $72,000 in 2006 and $45,000 in 2005.
Contingencies—We are subject to legal proceedings, claims and liabilities that arise in the ordinary course of
business. We accrue for losses associated with legal claims when such losses are considered probable and the
amounts can be reasonably estimated.
We self-insure the medical and dental coverage provided to certain employees, certain workers’ compensation and
the first $1 million of general liability coverage. Liabilities are accrued for self-insured claims, or when estimated
losses exceed coverage limits, and when sufficient information is available to reasonably estimate the amount of the
loss.
Electricity Generation—Ecuador Integrated Power Project—Through our subsidiaries, EDC Ecuador Ltd. and
MachalaPower Cia. Ltda., we have a 100% ownership interest in an integrated natural gas-to-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. The revenues attributable to the natural gas-to-power project are included
in other revenues and the expenses (including DD&A) are included in other expense, net.
Concentration of Market Risk—During 2007, Marathon Petroleum Supply Company (“Marathon”) was the largest
single non-affiliated purchaser of production and accounted for 18% of crude oil sales, or 10% of total oil and gas
sales. During 2006, Trafigura Beheer B.V. was the largest single non-affiliated purchaser of production and
accounted for 28% of crude oil sales, or 15% of total oil and gas sales. Shell Trading (US) Company accounted for
18% of 2006 crude oil sales or 10% of 2006 total oil and gas sales. During 2005, Glencore Energy U.K., Ltd. was
the largest single non-affiliated purchaser of production and accounted for 24% of crude oil sales, or 11% of total oil
and gas sales. We believe the loss of any one purchaser would not have a material effect on our financial position or
results of operation since there are numerous potential purchasers of our production.
Concentration of Credit Risk—Certain of our financial instruments, including cash equivalents, trade receivables and
derivative instruments, may expose us to credit risk. Substantially all of our cash at December 31, 2007 is located in
our foreign subsidiaries. The cash is denominated in US dollars and in invested in highly liquid, investment-grade
securities with original maturities of three months or less at the time of purchase. Although our cash and cash
equivalents are deposited with major international banks and financial institutions, concentrations of cash in certain
foreign locations may increase credit risk. We monitor the creditworthiness of the banks and financial institutions
with which we invest and review the securities underlying our investment accounts. We believe that losses from
nonperformance are unlikely to occur; however, we are not able to predict sudden changes in creditworthiness.
67
Our trade receivables result primarily from sales of crude oil and natural gas production and joint interest billings to
our partners. The trade receivables reflect a broad national and international customer base, which limits our
exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less,
and we continually monitor the creditworthiness of the counterparties.
We use crude oil and gas derivative instruments to mitigate the effects of commodity price fluctuations and these
derivative instruments expose us to counterparty credit risk. Our counterparties are major banks or financial
institutions. We engage in master netting arrangements to mitigate credit risk with counterparties as these
agreements permit the amounts owed to others to be offset against amounts due us. We monitor the creditworthiness
of our counterparties and believe that losses from nonperformance are unlikely to occur. However, we are not able
to predict sudden changes in counterparties’ creditworthiness.
Reclassification—Certain reclassifications have been made to the 2006 and 2005 consolidated financial statements
to conform to the 2007 presentation. These reclassifications are not material to the financial statements.
Note 3—Acquisitions and Divestitures
Sale of Argentina—In December 2007, we entered into an agreement to sell our interest in Argentina for a sales
price of $117.5 million, effective July 1, 2007. We expect the sale, which is subject to regulatory and partner
approvals, to close in 2008. The Argentina assets had a net book value of $82 million at December 31, 2007 and are
classified as assets held for sale in the consolidated balance sheets. The Argentina operations, financial position and
cash flows are not material and have not been reflected as discontinued operations.
Sale of Gulf of Mexico Shelf Properties—In 2006, we completed the sale of our Gulf of Mexico shelf properties. The
sale included essentially all of our properties in the Gulf of Mexico shelf except for our interest in the Main Pass
area, which we have retained. Pretax cash proceeds from the sale totaled $506 million including proceeds received
from parties who exercised preferential rights to purchase certain minor properties. We recorded a pretax gain of
$211 million from the sale. The net book value of properties sold totaled $229 million. Asset retirement obligations
of $45 million, related to the Gulf of Mexico shelf properties, were also included in the sale. In accordance with
SFAS 142, we allocated $100 million of our US reporting unit goodwill to the sale. The property disposition did not
qualify for accounting as discontinued operations, in accordance with EITF 03-13, “Applying the Conditions in
Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations”. This is due
to the migration of our investment and operations to the deepwater Gulf of Mexico which we believe is an area of
higher potential.
As a result of the sale, we recognized a pretax charge of $399 million related to cash flow hedge losses which were
reclassified from AOCL to earnings. This reclassification reflected the mark-to-market value of the cash flow
hedges that related to Gulf of Mexico shelf production. See Note 12—Derivative Instruments and Hedging
Activities.
Purchase of U.S. Exploration Holdings, Inc.—In 2006, we purchased the common stock of U.S. Exploration, a
privately held corporation, for a cash purchase price of $412 million plus liabilities assumed. U.S. Exploration’s
reserves and production are located in Colorado’s Wattenberg field. The total purchase price was allocated to the
assets acquired and liabilities assumed based on fair values at the acquisition date as follows:
• $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.
Patina Merger—In 2005, we completed the Patina Merger. Patina was an independent energy company engaged in
the acquisition, development and exploitation of crude oil and natural gas properties within the continental US.
Patina’s properties and oil and gas reserves are located principally in relatively long-lived fields with established
production histories. The properties are concentrated primarily in the Wattenberg field of Colorado’s D-J basin, the
Mid-continent area of western Oklahoma and the Texas Panhandle, and the San Juan basin in New Mexico. We
acquired the common stock of Patina for a total purchase price of approximately $4.9 billion, which was comprised
primarily of cash and our common stock, plus liabilities assumed. In exchange for Patina’s common stock and stock
options held by Patina’s employees, we issued 55.7 million shares of stock valued at $1.7 billion, issued options
valued at $105 million, paid $1.1 billion in cash to Patina shareholders and assumed debt of $611 million and
68
deferred taxes of $1.1 billion. The total purchase price was allocated to the assets acquired and liabilities assumed
based on fair values at the merger date as follows:
• $2.6 billion to proved oil and gas properties;
• $1.1 billion to unproved oil and gas properties;
• $875 million to goodwill; and
• $1.1 billion to deferred income taxes.
The following pro forma condensed combined financial information for the year ended December 31, 2005 was
derived from our historical financial statements and those of Patina and gives effect to the merger as if it had
occurred on January 1, 2005. The financial information has been included for comparative purposes and is not
necessarily indicative of the results that might have occurred had the merger taken place as of the dates indicated
and is not intended to be a projection of future results.
Revenues
Net income
Earnings per share:
Basic
Diluted
Year Ended December 31, 2005
(in thousands, except
per share amounts)
$
2,434,677
693,091
$
4.03
3.98
Note 4—Effect of Gulf Coast Hurricanes
We have completed our cleanup activities relating to damage to the Main Pass assets caused by Hurricane Ivan in
2004 and Katrina in 2005. During third quarter 2007, we completed the lifting and removal of the four platform
decks that were sheared from their supporting structures during the hurricanes. During the first half of 2007, several
factors contributed to an increase in our estimated cleanup costs for damage related to Hurricanes Ivan and Katrina.
These factors included cost escalation due to weather delays and an increase in effort for the design and construction
of the deck lifting barge and mooring system, as well as additional costs for the actual deck lifting activities. These
increases caused the total project costs, combined with net book value of the assets destroyed, to exceed certain
insurance coverage limitations. As a result, we recorded $51 million as a loss on involuntary conversion during
2007.
Through December 31, 2007, we received $310 million of insurance recoveries related to damage caused by
Hurricanes Ivan and Katrina. As of December 31, 2007, we recorded probable insurance claims of $40 million. We
are currently assessing the scope and timing of our redevelopment of the Main Pass properties. Ultimate recovery of
our insurance claim is associated with redevelopment or possible settlement resolution with our insurance providers.
Insurance reimbursements received to date have been for cleanup and repair costs and are included in cash flows
from operating activities.
69
Note 5—Capitalized Exploratory Well Costs
We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is
deemed noncommercial, in which case the well costs are immediately charged to exploration expense.
Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and
subsequently expensed in the same period:
2007
Year Ended December 31,
2006
(in thousands)
2005
Capitalized exploratory well costs, beginning of period
Additions to capitalized exploratory well costs
pending determination of proved reserves
Reclassified to property, plant and equipment
based on determination of proved reserves
Capitalized exploratory well costs charged to expense
$ 80,359 $ 35,228 $ 62,724
182,271 62,580 33,671
(7,143) (16,762) (52,138)
(6,454) (687) (9,029)
Capitalized exploratory well costs, end of period
$
249,033
$
80,359
$
35,228
The following table provides an aging of capitalized exploratory well costs (suspended well costs) based on the date
the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a
period greater than one year since the completion of drilling:
Capitalized exploratory well costs that have been
capitalized for a period of one year or less
Capitalized exploratory well costs that have been capitalized for a
period greater than one year after completion of drilling
Balance at end of period
2007
December 31,
2006
(in thousands)
2005
$
187,101
$
58,493
$
35,228
61,932
21,866
-
$
249,033
$
80,359
$
35,228
Number of projects that have exploratory well costs that have been
capitalized for a period greater than one year after completion of drilling
6
4
-
The following table provides a further aging of those exploratory well costs that have been capitalized for a period
greater than one year since the completion of drilling as of December 31, 2007:
Project:
Raton South (Deepwater Gulf of Mexico)
Redrock (Deepwater Gulf of Mexico)
Blocks O and I (West Africa)
Other
Total capitalized exploratory well costs that have been capitalized
for a period greater than one year after completion of drilling
Total
Suspended Since
2005
2006
(in thousands)
$
23,374
17,133
19,039
2,386
$
23,374
17,133
-
2,386
-
$
-
19,039
-
$
61,932
$
42,893
$
19,039
Exploratory well costs capitalized for more than one year at December 31, 2007 included six projects, two of which
included activity in the deepwater Gulf of Mexico. One project relates to Raton South (Mississippi Canyon Block
292) and includes approximately $23 million of suspended exploratory well costs. We are currently evaluating a
70
possible sidetrack-appraisal well to be drilled during late 2008 or 2009. The other project relates to Redrock
(Mississippi Canyon 248) and includes approximately $17 million of suspended exploratory well costs. Redrock is
currently considered a co-development candidate to a successful sidetrack-appraisal well at Raton South.
We also incurred exploratory well costs for projects, Block O and Block I, in West Africa. These exploratory well
costs totaled approximately $19 million. Since drilling the initial well for the project, additional seismic work has
been completed and appraisal wells have been drilled to further evaluate this discovery. In 2008, the West Africa
development team will proceed with a program to further define the resources in this area such that an optimal
development program may be designed. In addition to the amount of exploratory well costs that have been
capitalized for a period greater than one year for the Block O and Block I projects, we incurred $137 million related
to the six successful wells drilled in West Africa during 2007.
The remaining two projects, which total approximately $2 million, continue to be evaluated by various means
including additional seismic work, drilling additional wells and evaluating the potential of the exploration wells.
Note 6—Asset Retirement Obligations
Asset retirement obligations consist of estimated costs of dismantlement, removal, site reclamation and similar
activities associated with our oil and gas properties. An asset retirement obligation and the related asset
retirement cost are recorded when an asset is first constructed or purchased. The asset retirement cost is
determined and discounted to present value using a credit-adjusted risk-free rate. After initial recording the
liability is increased for the passage of time, with the increase being reflected as accretion expense in the
statement of operations. Subsequent adjustments in the cost estimate are reflected in the liability and the amounts
continue to be amortized over the useful life of the related long-lived asset.
Changes in asset retirement obligations are as follows:
Year Ended December 31,
2007
(in thousands)
Asset retirement obligations, beginning of period
Liabilities incurred in current period
Liabilities settled in current period
Revisions
Accretion expense
Asset retirement obligations, end of period
Current portion
Noncurrent portion
$
196,189
8,927
(176,961)
108,008
8,125
144,288
$
$
13,332
130,956
Approximately $125 million of liabilities settled and $64 million of revisions related to hurricane damage to the
Gulf of Mexico Main Pass assets. The remainder of the liabilities settled and revisions resulted primarily from
changes in estimated timing of actual abandonment and overall cost increases for Gulf of Mexico assets. See Note
4—Effect of Gulf Coast Hurricanes.
71
Note 7—Debt
Our debt consists of the following:
$2.1 billion Credit Facility
5 ¼% Senior Notes, due April 2014
7 ¼% Notes, due October 2023
8% Senior Notes, due April 2027
7 ¼% Senior Debentures, due August 2097
Installment payments, due May 2009
Long-term debt
Installment payments - current portion
Total debt
Unamortized discount
Total debt, net of discount
December 31,
2007
2006
Debt
Interest Rate
Debt
Interest Rate
(in thousands, except percentages)
5.28
5.25
7.25
8.00
7.25
5.53
5.53
$
1,180,000
200,000
100,000
250,000
100,000
25,000
1,855,000
25,000
1,880,000
(3,913)
$
1,876,087
$
1,155,000
200,000
100,000
250,000
100,000
-
1,805,000
-
1,805,000
(4,190)
$
1,800,810
5.69
5.25
7.25
8.00
7.25
-
-
All of our long-term debt is senior unsecured debt and is, therefore, pari passu with respect to the payment of both
principal and interest. The indenture documents of each of the 7¼% Notes, the 8% Senior Notes and the 7¼%
Senior Debentures provide that we may prepay the instruments by creating a defeasance trust. The defeasance
provisions require that the trust be funded with securities sufficient, in the opinion of a nationally recognized
accounting firm, to pay all scheduled principal and interest due under the respective agreements. Interest on each of
these issues is payable semi-annually.
Credit Facility—In November 2007, we extended our bank revolving credit facility (the “Credit Facility”) until
December 9, 2012. The commitment is $2.1 billion until December 9, 2011 at which time the commitment reduces
to $1.8 billion. The Credit Facility (i) provides for Credit Facility fee rates that range from 5 basis points to 15
basis points per year depending upon our credit rating, (ii) makes available short-term loans up to an aggregate
amount of $300 million and (iii) provides for interest rates that are based upon the Eurodollar rate plus a margin that
ranges from 20 basis points to 70 basis points depending upon our credit rating and utilization of the Credit Facility.
The Credit Facility requires that our total debt to capitalization ratio (as defined in the credit agreement), expressed
as a percentage, not exceed 60% at any time. A violation of this covenant could result in a default under the Credit
Facility, which would permit the participating banks to restrict our ability to access the Credit Facility and require
the immediate repayment of any outstanding advances under the Credit Facility. The Credit Facility is with certain
commercial lending institutions and is available for general corporate purposes.
Certain lenders that are a party to the Credit Facility have in the past performed investment banking, financial
advisory, lending or commercial banking services for us, for which they have received customary compensation and
reimbursement of expenses. Debt issuance costs of approximately $3 million remain and are being amortized to
expense over the life of the Credit Facility.
The Credit Facility does not restrict the payment of dividends on our common stock, except, if after giving effect
thereto, an Event of Default shall have occurred and be continuing or been caused thereby.
Installment Payments Due—During 2007, we purchased working interests in oil and gas properties in the Piceance
basin of western Colorado for $75 million. After making a cash payment of $25 million at closing, we owe $50
million in the form of installment payments to the seller. Installments of $25 million each are due on May 12, 2008
and May 11, 2009. The amount due in 2008 is included in short-term borrowings and the amount due in 2009 is
included in long-term debt in the consolidated balance sheets. Interest on the unpaid amounts is due quarterly.
Interest accrues at a LIBOR rate plus .30%. The interest rate was 5.53% at December 31, 2007.
Debt Repayments—During 2006, we prepaid the $105 million balance remaining on certain term loans due 2009.
The interest rates on the term loans were based on a Eurodollar rate plus a margin of between 60 to 130 basis points
72
depending upon our credit rating. Interest was payable periodically based on the tenor of the underlying Eurodollar
rate selected at the time of a rate reset.
Annual Maturities—Annual maturities of outstanding debt are as follows:
2008
2009
2010
2011
2012
Thereafter
Total
(in thousands)
$
25,000
25,000
-
-
1,180,000
650,000
1,880,000
$
Short-Term Borrowings—Our credit agreement is supplemented by short-term borrowings under various
uncommitted credit lines used for working capital purposes. Uncommitted credit lines may be offered by certain
banks from time to time at rates negotiated at the time of borrowing. Other than the installment payments discussed
above, no short-term borrowings were outstanding at December 31, 2007 or 2006.
Note 8—Income Taxes
Components of income before income taxes are as follows:
Domestic
Foreign
Total
The income tax provision consists of the following:
Current taxes:
Federal
State
Foreign
Total current
Deferred taxes:
Federal
State
Foreign
Total deferred
Total income tax provision
2007
2005
Year Ended December 31,
2006
(in thousands)
$
$
480,200
887,367
1,367,567
$
402,111
694,106
1,096,217
$
$
426,756
541,904
968,660
$
2007
Year Ended December 31,
2006
(in thousands)
2005
$
6,409
506
124,901
131,816
185,503
6,283
100,095
291,881
423,697
$
$
79,680
5,577
138,271
223,528
144,143
4,641
45,477
194,261
417,789
$
$
48,293
-
90,877
139,170
119,953
14,073
49,744
183,770
322,940
$
73
A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
Federal statutory rate
Effect of:
Earnings of equity method investees
State taxes, net of federal benefit
Difference between US and foreign rates
Nondeductible goodwill
AJCA repatriation benefit
Other, net
Effective rate
Deferred tax assets and liabilities resulted from the following:
2007
Year Ended December 31,
2006
(amounts in percentages)
2005
35.0
(5.4)
0.5
1.6
-
-
(0.7)
31.0
35.0
(4.2)
1.3
2.2
3.1
-
0.7
38.1
35.0
(3.2)
1.3
3.5
-
(3.7)
0.4
33.3
Deferred tax assets:
Loss carryforwards
Accrued expenses
Allowance for doubtful accounts
Fair value of derivative contracts
Postretirement benefits
Deferred compensation
Foreign tax credits
Other
Total deferred tax assets
Valuation allowance - foreign losses
Valuation allowance - foreign tax credits
Net deferred tax assets
Deferred tax liabilities:
Property, plant and equipment, principally due to
differences in depreciation, amortization,
lease impairment and abandonments
Other
Total deferred tax liability
Net deferred tax liability
December 31,
2007
2006
(in thousands)
$
20,571
26,227
3,566
176,750
10,233
60,993
82,037
14,037
394,414
(18,174)
(56,619)
319,621
$
90,387
34,083
2,917
185,667
14,578
55,880
63,707
3,577
450,796
(9,876)
(63,708)
377,212
(2,183,950)
11,067
(2,172,883)
(1,853,262)
$
(2,034,877)
(952)
(2,035,829)
(1,658,617)
$
Net deferred tax liabilities were classified in the consolidated balance sheet as follows:
December 31,
2007
2006
Deferred income tax asset
Deferred income tax liability
Net deferred tax liability
(in thousands)
130,571
(1,983,833)
(1,853,262)
$
$
99,835
(1,758,452)
(1,658,617)
$
$
In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion
or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon
74
the generation of future taxable income during the periods in which those temporary differences become deductible.
We consider the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning
strategies in making this assessment. Based upon the level of historical taxable income and projections for future
taxable income over the periods in which the deferred tax assets are deductible, we believe it is more likely than not
that we will realize the benefits of these deductible differences at December 31, 2007. The amount of the deferred
tax asset considered realizable could be reduced in the future if estimates of future taxable income during the
carryforward period are reduced.
We have recognized deferred tax assets associated with foreign loss carryforwards. The tax effect of these
carryforwards decreased from $90 million in 2006 to $18 million in 2007. These losses were incurred on our
projects in Suriname and other new venture activities which are not yet commercial. Therefore, a valuation
allowance was provided against the full amount of the deferred tax asset. In 2006, we incurred a large taxable loss
in the UK from accelerated write-offs allowed on our Dumbarton field development. No valuation allowance was
provided against this loss carryforward, and it was fully utilized in 2007. Starting in 2005, we were able to claim a
foreign tax credit for US federal income tax purposes and expect to be in a credit position for the next several years.
Therefore, we have recorded a deferred tax asset for certain foreign taxes paid in 2005 and 2006 that cannot be
claimed as a credit in those years because of limitations imposed by the Internal Revenue Code. A valuation
allowance of $11 million has been provided against this deferred tax asset. We have also recorded a deferred tax
asset of $71 million for the future foreign tax credits associated with deferred tax liabilities recorded by foreign
branch operations. A valuation allowance of $46 million has been provided against this deferred tax asset.
Several factors resulted in a decrease in our effective tax rate for 2007. The major factor was that, in 2006,
$100 million of goodwill write-off associated with the sale of the Gulf of Mexico shelf properties was not
deductible, which increased the rate for that year. Other factors were an increase in deferred tax assets arising from
foreign tax credits, a decrease in the Chinese tax rate, and the realization of additional income from equity method
investees which is a favorable permanent difference in calculating the income tax expense.
The American Jobs Creation Act (“AJCA”), enacted in 2004, created a temporary incentive for US corporations to
repatriate accumulated income earned abroad by providing for an 85% dividends-received deduction for certain
dividends from controlled foreign corporations. In July 2005, we completed an evaluation of the effects of the
repatriation provision, and our Board of Directors approved a plan to repatriate $118 million in earnings of our
methanol subsidiary during the third quarter 2005. Because we had provided US tax on most of the methanol
subsidiary’s earnings at 35% through December 31, 2004, repatriation under the Act resulted in a net tax benefit of
$35 million recorded in the third quarter 2005.
We have not recorded US deferred income taxes on the remaining undistributed earnings of foreign subsidiaries as
of December 31, 2007. As of December 31, 2007, the accumulated undistributed earnings of the consolidated
foreign subsidiaries were approximately $902 million. Upon distribution of these earnings in the form of dividends
or otherwise, we would likely be subject to US income taxes and foreign withholding taxes. It is not practicable,
however, to estimate the amount of taxes that may be payable on the eventual remittance of these earnings because
of the possible application of US foreign tax credits. Although we are currently claiming foreign tax credits, we may
not be in a credit position when any future remittance of foreign earnings takes place, or the limitations imposed by
the Internal Revenue Code and IRS Regulations may not allow the credits to be utilized during the applicable
carryback and carryforward periods.
During 2007, China’s legislature, the National People’s Congress, enacted the China Corporate Income Tax Law.
This new legislation will decrease our tax rate in China from 33% to 25% starting in 2008. The deferred tax liability
for China as of December 31, 2006 was revised during 2007 to reflect the new rate, which decreased deferred tax
expense by $2 million.
Adoption of FIN 48 and FSP FIN 48-1—As discussed in Note 2—Significant Accounting Policies, we adopted FIN
48 and FSP FIN 48-1 as of January 1, 2007. The adoption had no effect on our financial position or results of
operations. As of January 1, 2007, the total amount of unrecognized tax benefits was $400,000, all of which would
affect our effective tax rate if recognized. There was no change in the amount of unrecognized tax benefits through
December 31, 2007. We do not expect that the total amount of unrecognized tax benefits will significantly increase
or decrease during the next 12 months.
In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2004,
Equatorial Guinea – 2006, China – 2006, Israel – 2000, UK – 2006 and the Netherlands – 2005.
75
We recognize interest and penalties related to unrecognized tax benefits which have been claimed on tax returns in
income tax expense. We did not accrue interest or penalties at December 31, 2007, because the jurisdiction in which
we have unrecognized tax benefits does not currently impose interest on underpayments of tax, and we believe that
we are below the minimum statutory threshold for imposition of penalties.
Note 9—Stock-Based Compensation
As discussed in Note 2—Summary of Significant Accounting Policies, effective January 1, 2006, we adopted the
fair value recognition provisions for stock-based awards granted to employees using the modified prospective
application method provided by SFAS 123(R). Accordingly, prior period amounts have not been restated.
SFAS 123(R) requires companies to recognize in the statement of operations the grant-date fair value of stock
options and other stock-based compensation issued to employees and was effective for interim or annual periods
beginning January 1, 2006. We recognize the expense of all stock-based awards on a straight-line basis over the
employee’s requisite service period (generally the vesting period of the award).
We recognized total stock-based compensation expense as follows:
2007
Year Ended December 31,
2006
(in thousands)
2005
Stock-based compensation expense included in:
General and administrative expense
Exploration expense and other
Total stock-based compensation expense
$
$
$
$
25,136
1,689
26,825
10,720
1,096
11,816
$
$
4,008
-
4,008
Tax benefit recognized
$
10,086
$
4,443
$
1,403
Pro Forma Information—The following table illustrates the effect on net income and earnings per share if we had
applied the fair value recognition provisions of SFAS 123(R) to stock-based employee compensation in all periods
presented. The actual and pro forma net income and earnings per share for 2007 and 2006 below are the same since
we adopted SFAS 123(R) as of January 1, 2006. The 2007 and 2006 amounts are presented for comparison to the
prior year.
Year Ended December 31,
2006
(actual)
2007
(actual)
2005
(pro forma)
(unaudited)
Net income, as reported
Add: Stock-based compensation cost recognized, net of tax
Deduct: Stock-based employee compensation expense determined
under fair value based method for all awards, net of tax
Pro forma net income
Earnings per share:
Basic - as reported
Basic - pro forma
Diluted - as reported
Diluted - pro forma
(in thousands, except per share amounts)
$
943,870
16,739
$
678,428
7,373
$
645,720
2,605
(16,739)
943,870
$
(7,373)
678,428
$
(6,150)
642,175
$
$
5.52
5.52
5.45
5.45
$
3.86
3.86
3.79
3.79
$
4.20
4.18
4.12
4.10
Total stock-based compensation expense determined under the fair value based method for all awards for 2005 has
been recalculated using revised expected term assumptions. The impact on pro forma earnings and pro forma
earnings per share was not significant.
76
Stock Option and Restricted Stock Plans and Incentive Plan—Our stock option and restricted stock plans (the
“Plans”) and incentive plan are described below.
1992 Stock Option and Restricted Stock Plan
Under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended (the “1992 Plan”), the
Compensation, Benefits and Stock Option Committee of the Board of Directors (the “Committee”) may grant stock
options and award restricted stock to our officers or other employees and those of our subsidiaries. During 2007, our
stockholders approved an amendment to the 1992 Plan that increased the maximum number of shares of our
common stock that may be issued from 18,500,000 to 22,000,000 shares. At December 31, 2007, 11,229,753 shares
of common stock were reserved for issuance, including 6,063,665 shares available for future grants and awards,
under the 1992 Plan.
1992 Plan Stock Options—Stock options are issued with an exercise price equal to the market price of our common
stock on the date of grant, and are subject to such other terms and conditions as may be determined by the
Committee. Unless granted by the Committee for a shorter term, the options expire ten years from the grant date.
Option grants generally vest ratably over a three-year period.
1992 Plan Restricted Stock—Restricted stock awards made under the 1992 Plan are subject to such restrictions,
terms and conditions, including forfeitures, if any, as may be determined by the Committee. Restricted stock awards
generally vest over periods of one to three years.
2004 Long-Term Incentive Plan
Under the Noble Energy, Inc. 2004 Long-Term Incentive Plan (the “2004 LTIP”), the Committee may make
incentive awards to our key employees and those of our subsidiaries. Incentive compensation is based upon the
attainment of specific market and performance goals established by the Committee. Awards may be in the form
of stock options or restricted stock or in the form of performance units or other incentive measurements
providing for the payment of bonuses in cash, or in any combination thereof, as determined by the Committee in its
discretion. Stock options granted and restricted stock awarded under the 2004 LTIP are granted and awarded
pursuant to the terms of the 1992 Plan. These awards are accounted for in accordance with the provisions of SFAS
123(R) which provides for the grant-date fair value of the awards to be recognized in the income statement over the
service period. Our cash based performance units are accounted for under SFAS No. 5, “Accounting for
Contingencies” and are excluded from the provisions of SFAS 123(R).
2005 Stock Plan for Non-Employee Directors
The 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (the “2005 Plan”) provides for grants of
stock options and awards of restricted stock to our non-employee directors. The 2005 Plan superseded and replaced
the 1988 Nonqualified Stock Option Plan for Non-Employee Directors. The total number of shares of common stock
that may be issued under the 2005 Plan is 800,000. At December 31, 2007, 774,561 shares of common stock were
reserved for issuance, including 650,306 shares available for future grants and awards under the 2005 Plan.
2005 Plan Stock Options—The 2005 Plan provides for the granting to a non-employee director of 11,200 stock
options on the date of election to the Board of Directors, annual grants of 2,800 options per non-employee director
on February 1 of each year, and discretionary grants by the Board of Directors (up to a maximum of 11,200 options
per non-employee director granted in any one year). Options are issued with an exercise price equal to the market
price of our common stock on the date of grant and may be exercised one year after the date of grant. The options
expire ten years from the date of grant.
2005 Plan Restricted Stock—The 2005 Plan also provides for the granting to a non-employee director of 4,800
shares of restricted stock on the date of election to the Board of Directors, annual awards of 1,200 shares of
restricted stock per non-employee director on February 1 of each year, and discretionary grants by the Board of
Directors (up to a maximum of 4,800 shares of restricted stock per non-employee director awarded in any one year).
Restricted stock is restricted for a period of at least one year from the date of grant.
1988 Nonqualified Stock Option Plan for Non-Employee Directors
The 1988 Nonqualified Stock Option Plan for Non-Employee Directors of Noble Energy, Inc., as amended, (the
“1988 Plan”) provided for the issuance of stock options to our non-employee directors. Options issued under the
1988 Plan may be exercised one year after grant and expire ten years from the grant date. The 1988 Plan provided
for the granting of a fixed number of stock options to each non-employee director annually (10,000 stock options for
77
the first calendar year of service and 5,000 stock options for each year thereafter) on February 1 of each year. The
1988 Plan was terminated in 2005. No options can be granted under the 1988 Plan after its termination.
Patina Stock Option Plans
Patina maintained a shareholder approved stock option plan for employees (the “Patina Employee Plan”) that
provided for the issuance of options at prices not less than fair market value at the date of grant. Patina also
maintained a shareholder approved stock grant and option plan for non-employee directors (the “Patina Directors’
Plan”). The Patina Directors’ Plan provided for stock options to be granted to each non-employee director upon
appointment and upon annual re-election thereafter. Upon completion of the Patina Merger, all unvested stock
options outstanding under the Patina Employee Plan and the Patina Directors’ Plan became fully vested, and all
outstanding options were converted into options to purchase our common stock. The Patina options expire five years
from the date of grant. See Note 3—Acquisitions and Divestitures.
Stock Option Grants—The fair value of each stock option granted was estimated on the date of grant using a Black-
Scholes-Merton option valuation model that uses the assumptions noted in the following table. The expected term
represents the period of time that options granted are expected to be outstanding. The hypothetical midpoint scenario
we use considers the actual exercise and post-vesting cancellation history of stock-based compensation historical
trends to develop expectations for future periods. Expected volatility represents the extent to which our stock price is
expected to fluctuate between the grant date and the anticipated term of the award. We use a blended ratio of the
historical volatility of our common stock for a period equal to the expected term of the option and the implied
volatility from exchange-traded options on our common stock. The risk-free rate is based on a weighting of five and
seven year US Treasury securities as of the year ended prior to the date of grant to arrive at an approximated
5.5-year risk free rate of return. 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 are as follows:
2007
Year Ended December 31,
2006
(weighted averages)
2005
Expected term (in years)
Expected volatility
Risk-free rate
Expected dividend yield
Stock option activity was as follows:
Outstanding at December 31, 2006
Granted
Exercised
Forfeited/Canceled
Outstanding at December 31, 2007
Exercisable at December 31, 2007
5.5
29.6%
4.7%
0.6%
5.5
31.8%
4.7%
0.8%
5.5
21.5%
4.6%
0.4%
Weighted
Average
Exercise
Price
(per share)
$
24.24
53.79
16.66
49.21
32.98
24.29
$
$
Options
6,211,750
1,557,919
(1,479,040)
(115,568)
6,175,061
4,083,097
Weighted
Average
Remaining
Contractual
Term
(in years)
Aggregate
Intrinsic
Value
(in thousands)
5.5
3.8
$
$
287,768
225,499
The weighted-average grant-date fair value of options granted was $18.77 in 2007, $16.09 in 2006 and $12.17 in
2005. The total intrinsic value of options exercised was $68 million in 2007, $118 million in 2006 and $78 million
in 2005.
78
As of December 31, 2007, $23 million of compensation cost related to unvested stock options granted under the
Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.4 years.
We issue new shares of common stock to settle option exercises. Dividends are not paid on unexercised options.
Restricted Stock Awards—Awards of time-vested restricted stock are valued at the price of our common stock at the
date of award. The fair values of market-based restricted stock awards are estimated on the date of award using a
Monte Carlo valuation model that uses the assumptions in the following table. The Monte Carlo model is based on
random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment.
Expected volatility represents the extent to which our stock price is expected to fluctuate between now and the
award’s anticipated term. We use the historical volatility of our common stock for the three-year period ended prior
to the date of award. The risk-free rate is based on a three-year period from US Treasury securities as of the year
ended prior to the date of award. The assumptions used in valuing the market based restricted stock awards are as
follows:
Number of simulations
Expected volatility
Risk-free rate
Restricted stock activity was as follows:
Year Ended December 31,
2006
2005
100,000
28.4%
4.4%
100,000
29.6%
3.3%
Shares
Subject to
Service
Conditions
Weighted
Average
Grant Date
Fair Value
(per share)
$
Outstanding at December 31, 2006
Granted
Vested
Forfeited
Outstanding at December 31, 2007
73,095
547,818
(37,475)
(15,848)
567,590
35.85
53.92
42.99
53.42
52.33
$
Shares
Subject to
Market
Conditions
204,250
-
(75,325)
(4,788)
124,137
Weighted
Average
Grant Date
Fair Value
(per share)
29.27
$
-
22.23
40.51
33.11
$
The total fair value of restricted stock that vested was $6 million in 2007 and $2 million in 2006.
As of December 31, 2007, $20 million of compensation cost related to unvested restricted stock awarded under the
Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of two
years. Common stock dividends accrue on restricted stock grants and are paid upon vesting. We issue new shares of
common stock when awarding restricted stock.
79
Note 10—Additional Shareholders’ Equity Information
Activity in shares of our common stock and treasury stock was as follows:
Common stock shares issued
Shares at beginning of period
Exercise of common stock options
Restricted stock awards, net of forfeitures
Shares at end of period
Treasury stock
Shares at beginning of period
Shares repurchased
Rabbi trust shares sold
Shares at end of period
Year Ended December 31,
2006
2007
188,808,087
1,479,040
527,182
190,814,309
184,893,510
3,848,521
66,056
188,808,087
16,574,384
2,006,481
-
18,580,865
9,268,932
8,373,400
(1,067,948)
16,574,384
During 2007, we completed a $500 million common stock repurchase program begun in 2006.
Accumulated other comprehensive loss in the shareholders’ equity section of the balance sheet included:
Accumulated Other Comprehensive Loss
December 31, 2004
Cash flow hedges
Realized amounts reclassified into earnings
Unrealized amounts reclassified into earnings
Unrealized change in fair value
Net change in minimum pension liability and other
December 31, 2005
Cash flow hedges
Realized amounts reclassified into earnings
Unrealized amounts reclassified into earnings
Unrealized change in fair value
Net change in minimum pension liability and other
Adoption of SFAS 158
December 31, 2006
Cash flow hedges
Realized amounts reclassified into earnings
Unrealized change in fair value
Net change in other
December 31, 2007
Oil and Gas
Cash Flow
Hedges
$ (6,939)
Interest Rate
Lock Cash
Flow
Hedges
Minimum
Pension
Liability
and Other
(in thousands)
$
$ (4,577)
(3,271)
154,500
33,638
(945,033)
-
(763,834)
492
-
-
-
(4,085)
-
-
-
(12,309)
(15,580)
145,035
264,520
249,974
-
-
(104,305)
637
-
-
-
-
(3,448)
-
-
-
16,225
(33,401)
(32,756)
Total
$
(14,787)
154,992
33,638
(945,033)
(12,309)
(783,499)
145,672
264,520
249,974
16,225
(33,401)
(140,509)
33,761
(184,254)
-
$
(254,798)
473
(751)
-
$
(3,726)
2,000
5,095
$
(25,661)
36,234
(185,005)
5,095
(284,185)
$
The effective income tax rate applied to AOCL increased from 35% at December 31, 2005 to 37.6% at
December 31, 2006 and remained 37.6% at December 31, 2007.
Note 11—Benefit Plans
Pension Plan and Other Postretirement Benefit Plans—We have a noncontributory, tax-qualified defined benefit
pension plan covering employees who were hired prior to May 1, 2006. The benefits are based on an employee’s
years of service and average earnings for the 60 consecutive calendar months of highest compensation. Our funding
80
policy has been to make annual contributions equal to at least the minimum required contribution, but no greater
than the maximum deductible for federal income tax purposes. We also have an unfunded, nonqualified restoration
plan that provides the pension plan formula benefits that cannot be provided by the qualified pension plan because
of pay deferrals and the compensation and benefit limitations imposed on the pension plan by the Internal Revenue
Code of 1986, as amended. We sponsor other plans for the benefit of our employees and retirees, which include
medical and life insurance benefits. We use a December 31 measurement date for the plans.
Former Patina employees began participation in the pension plan and the restoration plan on January 1, 2006, with
vesting service from their original Patina hire date and credited service for benefit accruals starting January 1, 2006.
Additionally, all former Patina employees were covered under the medical and life insurance plans effective
January 1, 2006.
On December 31, 2006, we adopted SFAS 158, which required us to recognize the funded status (the difference
between the fair value of plan assets and the benefit obligation) of our defined benefit pension, restoration and other
postretirement benefit plans in the consolidated balance sheet, with a corresponding adjustment to AOCL, net of tax.
The adjustment to AOCL at adoption represented the unrecognized net actuarial loss, unrecognized prior service
cost, and unrecognized net transition obligation remaining from the initial adoption of SFAS No. 87, “Employers’
Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Post-Retirement Benefits Other Than
Pensions”. These amounts are currently being recognized as net periodic benefit cost pursuant to our historical
accounting policy for amortizing such amounts. Further, actuarial gains and losses that arise in periods subsequent to
adoption and are not recognized as net periodic benefit cost in the same periods are recognized as a component of
AOCL. The adoption of SFAS 158 had no effect on our consolidated statements of operations for the year ended
December 31, 2006, for any prior period presented, or for any periods subsequent to adoption.
81
Changes in the benefit obligation and plan assets of the pension, restoration and other postretirement benefit plans
are as follows at December 31:
Retirement and Restoration Plan
Medical and Life Plan
2006
2007
2006
(in thousands)
Change in benefit obligation
Benefit obligation at beginning of year
Service cost
Interest cost
Plan participants' contributions
Amendments
Benefits paid
Actuarial (gain) loss
Benefit obligation at end of year
Change in plan assets
Fair value of plan assets at beginning of year
Actual return on plan assets
Employer contributions
Plan participants' contributions
Benefits paid
Fair value of plan assets at end of year
Funded status
Funded status at end of year
Net amount recognized in consolidated
balance sheets (after adoption of FAS 158)
Amounts recognized in consolidated
balance sheets consist of:
Current liabilities
Noncurrent liabilities
Net amount recognized in consolidated
balance sheets (after adoption of FAS 158)
Amounts not yet reflected in net periodic
benefit cost and included in AOCL
Transition obligation
Prior service (cost) credit
Accumulated loss
AOCL
Cumulative employer contributions in excess
of net periodic benefit cost
Net amount recognized in consolidated
balance sheet (after adoption of FAS 158)
Change in AOCL due to adoption of FAS 158
Additional minimum liability (before FAS 158)
Intangible asset (before FAS 158)
AOCL (before FAS 158)
Net increase in AOCL
2007
$
175,154
11,671
9,978
-
7,836
(6,513)
(10,633)
187,493
136,890
12,982
11,395
-
(6,513)
154,754
$
168,301
11,781
9,550
-
(8,327)
(6,169)
18
175,154
94,832
12,593
35,634
-
(6,169)
136,890
$
22,373
1,962
1,191
332
-
(830)
(2,640)
22,388
$
27,223
2,207
1,377
272
(5,711)
(795)
(2,200)
22,373
-
-
498
332
(830)
-
-
-
523
272
(795)
-
(32,739)
(38,264)
(22,388)
(22,373)
(32,739)
(38,264)
(22,388)
(22,373)
(2,958)
(29,781)
(32,739)
(614)
(2,981)
(34,051)
(37,646)
4,907
(1,205)
(37,059)
(1,197)
(21,191)
(941)
(21,432)
(38,264)
(22,388)
(22,373)
(854)
5,372
(49,978)
(45,460)
-
5,746
(13,691)
(7,945)
-
6,672
(17,384)
(10,712)
7,196
(14,443)
(11,661)
$
(32,739)
(38,264)
$
(22,388)
(22,373)
(2,708)
65
(2,643)
(42,817)
$
-
-
-
(10,712)
$
82
Net periodic benefit cost recognized for the pension, restoration and other postretirement benefit plans is provided in
the table below.
Retirement and Restoration Plan
Year Ended December 31,
2006
2007
Medical and Life Plan
Year Ended December 31,
2006
2007
2005
2005
(in thousands)
Components of net periodic benefit cost
Service cost
Interest cost
Expected return on plan assets
Amortization of transition obligation
Amortization of prior service (credit) cost
Amortization of net loss
Net periodic benefit cost
Other changes recognized in AOCL
Prior service cost arising during period
Net gain arising during period
Amortization of transition obligation
Amortization of prior service credit
Amortization of net loss
Total recognized in AOCL
Expected amortizations for next fiscal year
Amortization of transition obligation
Amortization of prior service cost (credit)
Amortization of net loss
Additional Information
Increase in minimum liability included in AOCL
Weighted-average assumptions used to
determine benefit obligations
Discount rate
Rate of compensation increase
Weighted-average assumptions used to
determine net periodic benefit costs
Discount rate (1)
Expected long-term rate of return on plan assets
Rate of compensation increase
11,671
9,978
(11,045)
240
(516)
3,354
13,682
$
$
7,836
(12,571)
(240)
516
(3,354)
(7,813)
$
$
$
$
$
$
$
11,781
9,550
(9,320)
239
(220)
2,912
14,942
6,372
7,807
(7,094)
24
398
1,034
8,541
1,962
1,191
-
-
(925)
1,053
3,281
2,207
1,377
-
-
(439)
1,170
4,315
963
943
-
-
(236)
760
2,430
$
$
$
$
$
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
-
$
(2,639)
-
925
(1,053)
(2,767)
$
*
*
*
*
*
*
-
(925)
854
-
(925)
1,211
240
191
1,668
240
(516)
3,221
*
*
$
21,638
*
*
*
*
*
*
*
*
*
*
*
-
6.50%
5.00%
5.75%
5.00%
5.50%
5.00%
6.25%
-
5.75%
-
5.50%
-
5.75%
8.25%
5.00%
5.50% /
6.25%
8.25%
5.00%
6.00%
8.25%
4.00%
5.75%
-
-
5.50% /
6.25%
-
-
5.75%
-
-
*Not applicable due to change in method of accounting for defined benefit and other post retirement plans.
(1) The net periodic benefit cost was remeasured at May 1, 2006 using a discount rate of 6.25%, due to changes in
plan provisions.
83
Additional disclosures are as follows:
Accumulated benefit obligation
Information for pension plans with projected
benefit obligations in excess of plan assets
Projected benefit obligation
Fair value of plan assets
Information for pension plans with accumulated
benefit obligations in excess of plan assets
Accumulated benefit obligation
Fair value of plan assets
Retirement and Restoration Plan
2007
2006
(in thousands)
$
$
162,595
142,136
$
187,493
154,754
$
175,154
136,890
$
25,131
-
$
20,542
-
In selecting the assumption for expected long-term rate of return on assets, we consider the average rate of earnings
expected on the funds to be invested to provide for plan benefits. This includes considering the plan’s asset
allocation, historical returns on these types of assets, the current economic environment and the expected returns
likely to be earned over the life of the plan. We assume the long-term asset mix will be consistent with a target asset
allocation of 70% equity and 30% fixed income, with a range of plus or minus 10% acceptable degree of variation in
the plan’s asset allocation. Based on these factors we expect pension assets will earn an average of 8.25% per annum
over the life of the plan. No plan assets are expected to be returned to us during 2008.
In order to determine an appropriate discount rate at December 31, 2007, we performed an analysis of the Citigroup
Pension Discount Curve (the “CPDC”) as of that date for each of our plans. The CPDC uses spot rates that represent
the equivalent yield on high quality, zero coupon bonds for specific maturities. We used these rates to develop an
equivalent single discount rate based on our plans’ expected future benefit payment streams and duration of plan
liabilities. A 1% increase in the discount rate would have resulted in a decrease in net periodic benefit cost of
$4 million in 2007. A 1% decrease in the discount rate would have resulted in an increase in net periodic benefit cost
of $5 million in 2007.
Assumed health care cost trend rates were as follows at December 31:
Health care cost trend rate assumed for next year
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)
Year rate reaches ultimate trend rate
2007
9%
5%
2012
2006
10%
5%
2012
Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-
percentage-point change in assumed health care cost trend rates would have the following effects:
Effect on total service and interest cost components for 2007
Effect on year-end 2007 postretirement benefit obligation
1% Increase
1% Decrease
(in thousands)
$
390
2,270
$
(341)
(2,025)
84
Weighted-average asset allocations for the tax-qualified defined benefit pension plan are as follows:
Asset Category
Equity Securities
Fixed income
Other
Total
Target
Allocation
2008
70%
30%
-
100%
Plan Assets
2007
70%
30%
-
100%
2006
70%
28%
2%
100%
The investment policy for the tax-qualified defined benefit pension plan is determined by an employee benefits
committee (“the committee”) with input from a third-party investment consultant. Based on a review of historical
rates of return achieved by equity and fixed income investments in various combinations over multi-year holding
periods and an evaluation of the probabilities of achieving acceptable real rates of return, the committee has
determined the target asset allocation deemed most appropriate to meet the immediate and future benefit payment
requirements for the plan and to provide a diversification strategy which reduces market and interest rate risk. A 1%
increase (decrease) in the expected return on plan assets would have resulted in a (decrease) increase, respectively,
in net periodic benefit cost of $1 million in 2007.
We base our determination of the asset return component of pension expense on a market-related valuation of
assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses
over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the
difference between the expected return calculated using the market-related value of assets and the actual return
based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a five-
year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of
January 1, 2007, we had cumulative asset gains of approximately $3 million, which remain to be recognized in the
calculation of the market-related value of assets.
Contributions—As a result of previous contributions made to the pension plan, there are no required contributions
expected during 2008. We may, however, make additional contributions to our pension plan as determined by the
committee. We expect to make cash contributions of approximately $4 million to the unfunded restoration and
medical and life plans during 2008. This amount equals expected benefit payments from those plans. (unaudited).
Estimated Future Benefit Payments—As of December 31, 2007, the following future benefit payments are expected
to be paid:
2008
2009
2010
2011
2012
Years 2013 to 2017
Retirement and Restoration Plan
Medical and Life Plan
(in thousands)
$ 25,049
12,000
13,586
16,722
18,507
99,516
$
1,197
1,370
1,499
1,914
2,198
14,280
The estimate of expected future benefit payments is based on the same assumptions used to measure the benefit
obligation at December 31, 2007 and includes estimated future employee service.
401(k) Plan—We sponsor a 401(k) savings plan. All regular employees are eligible to participate. We make
contributions to match employee contributions up to the first 6% of compensation deferred into the plan, and certain
profit sharing contributions for employees hired on or after May 1, 2006, based upon their ages and salaries. We
made cash contributions of $6 million in 2007, $4 million in 2006 and $5 million in 2005.
Deferred Compensation Plan—In connection with the Patina Merger, we acquired the assets and assumed the
liabilities related to a Patina shareholder-approved non-qualified deferred compensation plan. This plan was
available to officers and certain managers of Patina and allowed participants to defer all or a portion of their salary
85
and annual bonuses (either in cash or common stock). Participant-directed investments are held in a rabbi trust and
are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Participants may elect to
receive distributions in either cash or shares of our common stock. We account for the deferred compensation plan
in accordance with EITF 97-14, “Accounting for Deferred Compensation Arrangements Where Amounts Earned are
Held in a Rabbi Trust and Invested.” Components of the rabbi trust are as follows:
Rabbi trust assets
Mutual fund investments
Noble Energy common stock (at market value)
Total rabbi trust assets
Liability under Patina deferred compensation plan
Number of shares of Noble Energy common stock held by rabbi trust
December 31,
2007
2006
(in thousands)
$
106,581
87,554
194,135
$
194,135
1,101,032
$
100,767
54,027
154,794
$
154,794
1,101,032
Assets of the rabbi trust, other than our common stock, are invested in certain mutual funds that cover an investment
spectrum ranging from equities to money market instruments. These mutual funds have published market prices and
are reported at market value. We account for these investments in accordance with SFAS No. 115, “Accounting for
Certain Investments in Debt and Equity Securities.” The mutual funds are included in the mutual funds account in
other noncurrent assets in the consolidated balance sheets. Shares of our common stock held by the rabbi trust are
accounted for as treasury stock in the shareholders’ equity section of the consolidated balance sheets. The amounts
payable to the plan participants are included in other noncurrent liabilities in the consolidated balance sheets and
include the market value of the shares of our common stock. One million shares, or 91%, of the common stock held
in the plan at December 31, 2007 and 2006 were attributable to a member of our Board of Directors. Plan
participants sold no shares of common stock during 2007, 1,067,948 shares during 2006 and 20,434 shares during
2005. Proceeds were invested in mutual funds. Distributions to plan participants totaled $2 million in 2007,
$0.5 million in 2006 and $1 million in 2005.
In accordance with EITF 97-14, all fluctuations in market value of the deferred compensation liability have been
reflected in other expense, net in the consolidated statements of operations. The market value of the liability
increased $41 million in 2007, $28 million in 2006 and $18 million in 2005. The increases in the liability included
the appreciation in the market value of our common stock of $34 million in 2007, $16 million in 2006 and $15
million in 2005. The increases in the liability also included the appreciation in the market value of the rabbi trust
mutual fund investments of $7 million in 2007, $12 million in 2006 and $3 million in 2005. Net deferred
compensation expense totaled $34 million, $16 million and $15 million in 2007, 2006 and 2005, respectively.
Note 12—Derivative Instruments and Hedging Activities
Cash Flow Hedges—We use various derivative instruments in connection with anticipated crude oil and natural gas
sales to mitigate the variability of cash flows associated with commodity price fluctuations. Such instruments
include variable to fixed price swaps, costless collars and basis swaps. While these instruments mitigate the cash
flow risk of future reductions in commodity prices they may also curtail benefits from future increases in commodity
prices. We account for derivative instruments and hedging activities in accordance with SFAS 133 and elected to
designate the majority of our commodity derivative instruments as cash flow hedges through December 31, 2007.
As discussed in Note 2—Summary of Significant Accounting Policies, we voluntarily discontinued cash flow hedge
accounting for our commodity derivative instruments, effective January 1, 2008.
(Gain) loss on derivative instruments includes the following:
Ineffectiveness (gains) losses
Reclassified from AOCL
Mark-to-market gain on derivative instruments
not accounted for as cash flow hedges
(Gain) loss on derivative instruments
2007
Year Ended December 31,
2006
(in thousands)
$
$
(2,520)
-
9,502
423,910
$
930
51,750
2005
-
(2,520)
$
(41,045)
392,367
$
(20,000)
32,680
$
86
If it becomes probable that the hedging instrument is no longer highly effective, the hedging instrument loses
hedge accounting treatment. All current mark-to-market gains and losses are recorded in earnings and all
accumulated gains or losses recorded in AOCL related to the hedging instrument are 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. 2006
also included a mark-to-market gain of $39 million and the reclassification 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. During 2005, we recognized a mark-to-market gain of $20 million and reclassified a pretax charge of
$52 million from AOCL to earnings due to the impact of Hurricanes Katrina and Rita on forecasted Gulf of Mexico
production.
Effects of cash flow hedges included in oil and gas sales were as follows:
Decrease in crude oil sales
Increase (decrease) in natural gas sales
Total decrease in crude oil and natural gas sales
2007
Year Ended December 31,
2006
(in thousands)
(190,730)
(41,698)
(232,428)
$
2005
(140,486)
(97,206)
(237,692)
$
(223,347)
169,242
(54,105)
$
As of December 31, 2007, we had entered into, and designated as cash flow hedges, the following variable to fixed
price swap derivative instruments related to natural gas and crude oil sales as follows:
Production Period
2008 (NYMEX)
2008 (Brent)
2009 (NYMEX)
2009 (Brent)
Natural Gas
Crude Oil
MMBtupd
Average Price
per MMBtu
Bopd
Average price
per Bbl
170,000
$
5.66
16,500
$
38.23
-
-
-
-
-
-
2,000
7,000
2,000
88.18
86.67
87.98
On January 2, 2008, we entered into additional NYMEX variable to fixed price swap derivative instruments for
1,000 Bpd of crude oil at an average price per Bbl of $90.50 for 2009.
As of December 31, 2007, we had entered into the following basis swap derivative instruments related to natural gas
sales. These basis swaps were combined with NYMEX variable to fixed swaps and designated as cash flow hedges:
Production Period
2008 (CIG (1) vs. NYMEX)
2008 (ANR (2) vs. NYMEX)
2008 (PEPL (3) vs. NYMEX)
(1) Colorado Interstate Gas – Northern System
(2) ANR Oklahoma Pipeline
(3) Panhandle Eastern Pipe Line
Average
Differential
per MMBtu
$
1.66
1.01
0.98
MMBtupd
100,000
40,000
10,000
87
As of December 31, 2007, we had entered into, and designated as cash flow hedges, the following costless collar
derivative instruments related to crude oil and natural sales as follows:
Natural Gas
Average Price
per MMBtu
Crude Oil
Average Price
per Bbl
Production Period
MMBtupd
Floor
Ceiling
Bopd
Floor
Ceiling
2008 (NYMEX)
2008 (CIG)
2008 (Brent)
2009 (NYMEX)
2009 (CIG)
2009 (Brent)
2010 (NYMEX)
2010 (CIG)
-
14,000
-
-
15,000
-
-
15,000
$ -
6.75
-
-
6.00
-
-
6.25
$ -
8.70
-
-
9.90
-
-
8.10
3,100
-
4,074
3,700
-
3,074
3,500
-
$ 60.00
-
45.00
60.00
-
45.00
55.00
-
$ 72.40
-
66.52
70.00
-
63.04
73.80
-
The costless collar, fixed price swap and basis swap contracts entitle us (floating price payor) to receive settlement
from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement
price for the scheduled trading days applicable for each calculation period is less than the fixed price or floor price.
We would pay the counterparty if the settlement price for the scheduled trading day applicable for each calculation
period is more than the fixed price or ceiling price. The amount payable by us, if the floating price is above the fixed
or ceiling price, is the product of the notional quantity per calculation period and the excess, if any, of the floating
price over the fixed or ceiling price in respect of each calculation period. The amount payable by the counterparty, if
the floating price is below the fixed or floor price, is the product of the notional quantity per calculation period and
the excess, if any, of the fixed or floor price over the floating price in respect of each calculation period.
AOCL—As of December 31, 2007 and 2006, the balance in AOCL included net deferred losses of $255 million and
$104 million, respectively, related to the fair value of crude oil and natural gas derivative instruments accounted for
as cash flow hedges. The net deferred losses are net of deferred income tax benefits of $153 million and $63 million,
respectively. Approximately $206 million of these deferred losses, net of tax, will be reclassified to earnings during
the next twelve months as the forecasted transactions occur, and will be recorded as a reduction in oil and gas sales
of approximately $331 million before tax. All forecasted transactions currently being hedged are expected to occur
by December 2010.
Other Derivative Instruments—In addition to the derivative instruments described above, we may employ derivative
instruments in connection with purchases and sales of production in order to establish a fixed margin and mitigate
the risk of price volatility. Most of the purchases are on an index basis. However, purchasers in the markets in which
we sell often require fixed or NYMEX-related pricing. We may use a derivative instrument to convert the fixed or
NYMEX sale to an index basis thereby determining the margin and minimizing the risk of price volatility.
Receivables/Payables Related to Crude Oil and Natural Gas Derivative Instruments—The fair values of derivative
instruments included in the consolidated balance sheets are as follows:
Crude oil and natural gas derivative instruments
Current asset
Long-term asset
Current liability
Long-term liability
December 31,
2007
2006
(in thousands)
$
15,058
4,829
(540,217)
(82,803)
$
35,242
2,862
(254,625)
(328,875)
Interest Rate Lock—We occasionally enter into forward contracts or swap agreements to hedge exposure to interest
rate risk. Changes in fair value of interest rate swaps or interest rate “locks” used as cash flow hedges are reported in
AOCL, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded
as adjustments to interest expense over the term of the related notes. At December 31, 2007, AOCL included a
88
deferred loss of $4 million, net of tax, related to interest rate swaps. $3 million of this amount is being reclassified
into earnings, at the rate of $0.8 million per year, as an adjustment to interest expense over the term of our 5¼%
senior notes due 2014. The remaining $1 million deferred loss relates to two $500 million notional amount interest
rate locks based on five and ten year US Treasury rates of 3.55% and 4.15%, respectively. The locks expire in
September 2008.
Note 13—Equity Method Investments
Investments accounted for under the equity method consist primarily of the following:
• 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.
Construction of the Alba Plant was funded primarily through advances by us and other owners in exchange for notes
payable by the Alba Plant. The notes were scheduled to mature on December 31, 2011 and bore interest at the
90-day LIBOR rate plus 3%. The notes were repaid in 2006.
Equity method investments are included in other noncurrent assets in the consolidated balance sheets, and our share
of earnings is reported as income from equity method investees in the consolidated statements of operations. Our
share of income taxes incurred directly by the equity method investees is reported in income from equity method
investments and is not included in our income tax provision in our consolidated statements of operations. At
December 31, 2007, our retained earnings included $151 million related to the undistributed earnings of equity
method investees.
The carrying value of our equity method investments is $29 million higher than the underlying net assets of the
investees. A portion of the basis difference is being amortized into income over the remaining useful lives of the
underlying net assets and the remainder is being recovered through distributions.
Equity method investments are as follows:
December 31,
2007
2006
(in thousands)
$
$
199,605
142,540
14,984
357,129
$
211,325
146,051
15,996
$ 373,372
Equity method investments
AMPCO
Alba Plant
Other
Total equity method investments
89
Summarized, 100% combined financial information for equity method investees is as follows:
Balance sheet information
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
Statements of operations information
Operating revenues
Less cost of goods sold
Gross margin
Less other expense
Less income tax expense
Net income
Note 14—Commitments and Contingencies
December 31,
2007
2006
(in thousands)
$
408,000
813,601
273,164
31,278
$
252,201
857,465
171,028
2,385
2007
Year Ended December 31,
2006
(in thousands)
2005
$
$
$
934,419
220,101
714,318
36,486
44,150
633,682
702,556
202,304
500,252
47,487
23,451
429,314
$
$
$
464,000
136,508
327,492
35,798
67,142
224,552
Legal Proceedings—We are among a group of eighteen defendants named in a lawsuit filed August 23, 2002 by
Dore Energy Corporation under Docket Number 10-16202 in the 38th Judicial District Court, Cameron Parish,
Louisiana. The lawsuit alleges damage to property owned by Dore resulting from oil and gas activities dating to the
1930’s. Our predecessor, Samedan Oil Corporation, operated on a portion of the property from 1989 to 1999. Dore
has delivered documents alleging approximately $140 million in damages. Trial is currently set for April 14, 2008.
We intend to vigorously defend against these allegations and believe that our share of damages, if any, will not have
a material adverse effect on our results of operations, financial condition or liquidity.
The Illinois Environmental Protection Agency (“IEPA”) issued a notice of violation to Equinox Oil Company on
September 25, 2001 alleging violation of air emission and permitting regulations for a facility known as the Zif Gas
Plant located near Clay City, Illinois. On January 17, 2007, the IEPA re-issued written notices of these alleged
violations in the name of Equinox’s successors in interest, and our wholly-owned subsidiaries, Elysium Energy,
LLC and Noble Energy Production, Inc. On March 16, 2007, the IEPA accepted our compliance commitment
agreement wherein we agreed to pay a delayed permit fee, install an incineration/caustic scrubber emissions control
system at the site, and fund a supplemental environmental project (“SEP”) in the nearby community. At this time,
we expect no additional monies to be expended other than these amounts for which we have fully accrued. As of
December 31, 2007, this matter has been concluded.
We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to
the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we do not
believe that the ultimate disposition of such proceedings will have a material adverse effect on our consolidated
financial position, results of operations or cash flows.
Non-Cancelable Leases and Other Commitments—We hold leases and other commitments for drilling rigs,
buildings, equipment and other properties. Rental expense for office buildings and oil and gas operations equipment
was approximately $13 million in 2007, $12 million in 2006 and $10 million in 2005.
90
Minimum commitments as of December 31, 2007 consist of the following:
$
$
$
$
Drilling and
Equipment,
and Purchase
Obligations
443,926
94,444
79,491
65,715
41,772
-
725,348
Throughput
Agreement
$ -
19,000
19,000
19,000
19,000
19,000
$
95,000
Office
Buildings and
Facilities
(in thousands)
Oil and Gas
Operations
Equipment
Total
7,289
7,426
7,069
6,736
6,511
17,863
52,894
5,467
4,448
2,159
-
-
-
12,074
456,682
125,318
107,719
91,451
67,283
36,863
885,316
$
$
$
$
2008
2009
2010
2011
2012
2013 and thereafter
Total
Note 15—Segment Information
We have operations throughout the world and manage our operations by country. The following information is
grouped into five components that are all primarily in the business of natural gas and crude oil exploration and
production: the United States; West Africa; the North Sea; Israel; and Other International, Corporate and Marketing.
Other International includes Argentina, China, Ecuador and Suriname.
Accounting policies for geographical segments are the same as those described in the summary of significant
accounting policies. Transfers between segments are accounted for at market value. We do not consider interest
income and expense or income tax benefit or expense in our evaluation of the performance of geographical
segments.
91
Year Ended December 31, 2007
Revenues from third parties
Intersegment revenue
Income from equity method investees
Total Revenues
DD&A
Gain on derivative instruments
Loss on involuntary conversion
Income (loss) before taxes
Investments in equity method investees
Additions to long-lived assets
Total assets at December 31, 2007 (1)
Year Ended December 31, 2006
Revenues from third parties
Intersegment revenue
Income from equity method investees
Total Revenues
DD&A
Loss on derivative instruments
Income (loss) before taxes
Investments in equity method investees
Additions to long-lived assets
Total assets at December 31, 2006 (1)
Year Ended December 31, 2005
Revenues from third parties
Intersegment revenue
Income from equity method investees
Total Revenues
DD&A
Loss on derivative instruments
Loss on involuntary conversion
Income (loss) before taxes
Investments in equity method investees
Additions to long-lived assets
Total assets at December 31, 2005 (1)
Total
United
States
West
Africa
North Sea
Israel
(in thousands)
Other Int'l,
Corporate &
Marketing
$
3,061,102
-
210,928
3,272,030
$
1,609,626
342,809
-
1,952,435
$
405,988
-
210,928
616,916
$
727,981
(2,520)
51,406
1,367,567
357,129
990,861
574,001
(2,520)
51,406
809,806
357,129
877,941
25,315
-
-
517,450
-
23,155
363,886
-
-
363,886
79,450
-
-
220,779
-
40,969
$
113,001
-
-
113,001
$
568,601
(342,809)
-
225,792
17,842
-
-
86,022
-
24,716
31,373
-
-
(266,490)
-
24,080
727,995
10,830,896
7,917,771
1,354,604
562,140
268,386
$
2,800,720
-
139,362
2,940,082
$
1,510,689
425,901
-
1,936,590
$
413,682
-
139,362
553,044
$
115,232
-
-
115,232
$
92,373
-
-
92,373
$
668,744
(425,901)
-
242,843
622,608
392,367
1,096,217
373,372
1,916,139
9,588,625
543,431
392,367
631,087
-
1,615,435
7,224,920
23,620
-
493,777
373,372
35,121
960,357
$
2,095,911
-
90,812
2,186,723
$
913,564
460,808
-
1,374,372
$
281,902
-
90,812
372,714
$
390,544
32,680
1,000
968,660
311,153
32,680
1,000
585,988
420,362
4,382,005
8,878,033
-
4,345,604
6,577,853
27,121
-
-
309,239
420,362
2,738
877,409
8,123
-
72,803
-
234,877
343,236
123,584
-
-
123,584
9,888
-
-
88,524
-
15,287
146,311
13,947
-
71,318
-
841
256,913
33,487
-
(172,768)
-
29,865
803,199
$
65,050
-
-
65,050
$
711,811
(460,808)
-
251,003
11,188
-
-
46,468
-
5,928
266,312
31,194
-
-
(61,559)
-
12,448
1,010,148
(1) The US reporting unit includes goodwill of $760 million at December 31, 2007, $781 million at December 31,
2006 and $863 million at December 31, 2005.
Note 16—Recently Issued Pronouncements
SFAS 141(R) and SFAS 160 – In December 2007, the FASB issued SFAS 141(R), “Business Combinations” (SFAS
141(R)”) and SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements” (SFAS 160”). These
statements require most identifiable assets, liabilities and noncontrolling interests to be recorded at full fair value
and require noncontrolling interests to be reported as a component of equity. Both statements are effective for
periods beginning on or after December 15, 2008, and earlier adoption is prohibited. SFAS 141(R) will be applied to
business combinations occurring after the effective date and SFAS 160 will be applied prospectively to all
noncontrolling interests, including any that arose before the effective date. We are currently evaluating the
provisions of SFAS 141(R) and SFAS 160 and assessing the impact, if any, they may have on our financial position
and results of operations.
92
SFAS 157—Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS 157”),
establishes a single authoritative definition of fair value based upon the assumptions market participants would use
when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop
those assumptions. Under the standard, additional disclosures are required, including disclosures of fair value
measurements by level within the fair value hierarchy. SFAS 157 is effective for fair value measures already
required or permitted by other standards for fiscal years beginning after November 15, 2007 and interim periods
within those fiscal years. For non-financial assets and liabilities, the adoption of SFAS No. 157 has been deferred
until January 1, 2009. We are adopting SFAS 157 as of January 1, 2008 and are currently in the process of
determining the effects of adoption, such as the effect of incorporating our own credit standing in the measurement
of certain liabilities. We do not expect that the final effects of adoption will have a significant impact on our
consolidated financial statements.
SFAS 159—In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and
Financial Liabilities” (“SFAS 159”). SFAS 159 provides companies with an option to report selected financial assets
and liabilities at fair value. SFAS 159 is effective as of the beginning of an entity’s first fiscal year beginning after
November 15, 2007. We adopted SFAS 159 as of January 1, 2008. Adoption had no effect on our financial position
or results of operations as we made no elections to report selected financial assets or liabilities at fair value.
FSP FIN 39-1—In April 2007, the FASB issued FSP FIN 39-1, “An Amendment of FASB Interpretation No. 39”
(“FSP FIN 39-1”). FSP FIN 39-1 allows companies to offset fair value amounts recognized for derivative
instruments and the fair value amounts recognized for the right to reclaim cash collateral or the obligation to return
cash collateral. The cash collateral must arise from derivative instruments recognized at fair value that are executed
with the same counterparty under a master netting arrangement. A company must make an accounting policy
decision whether or not to offset fair value amounts. FSP FIN 39-1 is effective for fiscal years beginning after
November 15, 2007 and is to be applied retrospectively. We are currently evaluating the provisions of FSP FIN 39-1
and assessing the impact it may have on our financial position and results of operations.
93
Supplemental Oil and Gas Information (Unaudited)
In accordance with SFAS No. 69, “Disclosures about Oil and Gas Producing Activities” (“SFAS 69”), and
regulations of the SEC, we are making the following supplemental disclosures about our crude oil and natural gas
exploration and production operations.
There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves.
Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of
crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the
quality of available data and of engineering and geological interpretation and judgment.
Engineers in our Houston, Denver and London offices prepare all reserve estimates for our different geographical
regions. These reserve estimates are reviewed and approved by senior engineering staff and division management
with final approval by the Director of Asset Development and certain members of senior management. During each
of the years 2007, 2006 and 2005, we retained Netherland, Sewell & Associates, Inc. (“NSAI”), independent third-
party reserve engineers, to perform reserve audits of proved reserves. The reserve audit for 2007 included a detailed
review of 16 of our major international, deepwater Gulf of Mexico and US fields, which covered approximately
71% of US proved reserves and 96% of international proved reserves (81% of total proved reserves). The reserve
audit for 2006 included a detailed review of 14 of our major international, deepwater Gulf of Mexico and US fields,
which covered approximately 80% of our total proved reserves. The reserve audit for 2005 included a detailed
review of 11 of our major international, deepwater Gulf of Mexico and US fields, which covered approximately
72% of our total proved reserves. See Items 1 and 2. Business and Properties—Proved Reserves.
Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such
estimate. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are
ultimately recovered.
Our supplemental disclosures are grouped by geographic area and include the United States, West Africa (Equatorial
Guinea and Cameroon), Israel, Ecuador, North Sea and Other International (Argentina, China and Suriname).
Operations in Equatorial Guinea, Cameroon, Ecuador, China and Suriname are conducted in accordance with the
terms of production sharing contracts.
The following definitions apply to the terms used in the paragraphs above:
Reserve Estimate. The determination of an estimate of a quantity of oil or gas reserves that are thought to exist at a
certain date, considering existing prices and reservoir conditions.
Reserve Audit. The process involving an independent third-party engineering firm’s visits, collection of any and all
required geologic, geophysical, engineering and economic data, and such firm’s complete external preparation of
reserve estimates.
The following definitions apply to our categories of proved reserves:
Proved Reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas
liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future
years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date
the estimate is made). Prices include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.
Proved Developed Reserves. Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
94
Proved Undeveloped Reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is
required for recompletion.
For complete definitions of proved natural gas, natural gas liquids and crude oil reserves, refer to Regulation S-X,
Rule 4-10(a)(2), (3) and (4).
Proved Gas Reserves (Unaudited)
The following reserve schedule was developed by our reserve engineers and sets forth the changes in estimated
quantities of proved natural gas reserves:
United
States
West
Africa
Natural Gas and Casinghead Gas (MMcf)
Israel
Ecuador
North
Sea
Other
Int'l (1)
Proved reserves as of:
December 31, 2004
Revisions of previous estimates (2)
Extensions, discoveries and other additions (3)
Purchase of minerals in place (4)
Sale of minerals in place
Production
December 31, 2005
Revisions of previous estimates (5)
Extensions, discoveries and other additions (6)
Purchase of minerals in place (7)
Sale of minerals in place (8)
Production
December 31, 2006
Revisions of previous estimates (9)
Extensions, discoveries and other additions (10)
Purchase of minerals in place
Sale of minerals in place
Production
December 31, 2007
Proved developed reserves as of:
December 31, 2004
December 31, 2005
December 31, 2006
December 31, 2007
519,735
18,644
144,335
1,083,959
-
(125,543)
1,641,130
(82,371)
314,140
141,610
(110,486)
(164,830)
1,739,193
(67,003)
315,687
2,957
(1)
(150,457)
1,840,376
917,409
7,732
-
-
-
(23,938)
901,203
57,543
-
2,532
-
(16,579)
944,699
44,256
-
-
-
(48,349)
940,606
417,293
481
-
-
-
(24,228)
393,546
260
-
-
-
(33,906)
359,900
(52)
-
-
-
(40,449)
319,399
119,341
32,800
-
-
-
(8,321)
143,820
32,927
-
-
-
(8,933)
167,814
29,872
-
-
-
(9,385)
188,301
430,513
1,278,788
1,255,271
1,259,331
447,347
431,142
359,691
830,191
360,428
336,681
303,035
262,534
119,341
143,820
167,814
188,301
11,714
3,200
-
-
-
(3,394)
11,520
10,485
-
-
-
(2,967)
19,038
(1,062)
3,086
-
-
(2,276)
18,786
11,714
11,520
19,038
15,700
Total
1,986,861
61,556
144,335
1,083,959
-
(185,492)
3,091,219
19,122
314,140
144,142
(110,486)
(227,323)
3,230,814
5,841
318,773
2,957
(1)
(250,916)
3,307,468
1,369
(1,301)
-
-
-
(68)
-
278
-
-
(108)
170
(170)
-
-
-
-
-
1,118
-
170
-
1,370,461
2,201,951
2,105,019
2,556,057
(1) Other International includes Argentina. We have entered into an agreement to sell our interest in Argentina effective July 1,
2007. We expect the sale, which is subject to regulatory and partner approvals, to close in 2008.
Increases for Ecuador are due to better than expected performance.
(2)
(3) The increase in US proved reserves includes 57 Bcf in the Wattenberg field and 40 Bcf in the Mid-continent area, primarily
due to infill drilling activities.
Purchase of minerals in place is the result of the Patina Merger. See Note 3—Acquisitions and Divestitures.
Increases for Ecuador and North Sea are due to better than expected performance.
(4)
(5)
(6) The increase in US proved reserves includes 140 Bcf in the Wattenberg field, 77 Bcf in the Piceance basin and 55 Bcf in the
(7)
(8)
Mid-continent area, primarily due to infill drilling activities.
Purchase of minerals in place includes 128 Bcf acquired in the purchase of U.S. Exploration. See Note 3—Acquisitions and
Divestitures.
Sale of minerals in place is primarily due to sale of Gulf of Mexico shelf properties. See Note 3—Acquisitions and
Divestitures.
(9) The negative revisions within the US are primarily due to 103 Bcf of natural gas being reflected in the proved oil reserve
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.
(10) 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.
95
Proved Oil Reserves (Unaudited)
The following reserve schedule was developed by our reserve engineers and sets forth the changes in estimated
quantities of proved crude oil reserves:
Crude Oil, Condensate and NGLs (MBbls)
North
Sea
Other
Int'l (1)
West
Africa
United
States
Proved reserves as of:
December 31, 2004
Revisions of previous estimates
Extensions, discoveries and other additions (2)
Purchase of minerals in place (3)
Sale of minerals in place
Production (9)
December 31, 2005
Revisions of previous estimates
Extensions, discoveries and other additions (4)
Purchase of minerals in place (5)
Sale of minerals in place (6)
Production (9)
December 31, 2006
Revisions of previous estimates (7)
Extensions, discoveries and other additions (8)
Purchase of minerals in place
Sale of minerals in place
Production (9)
December 31, 2007
Proved developed reserves as of:
December 31, 2004
December 31, 2005
December 31, 2006
December 31, 2007
55,066
4,192
11,272
90,594
-
(9,468)
151,656
(193)
23,037
19,328
(6,971)
(16,715)
170,142
27,998
26,634
-
(1,903)
(15,451)
207,420
108,730
(120)
-
-
-
(7,675)
100,935
(1,327)
-
138
-
(9,450)
90,296
229
-
-
-
(8,305)
82,220
32,390
114,223
114,505
128,879
108,730
100,935
90,296
71,409
9,336
278
12,955
-
-
(1,964)
20,605
(396)
-
-
-
(1,357)
18,852
776
10,094
-
-
(4,564)
25,158
9,336
7,650
18,852
15,064
Total
193,464
4,518
24,227
90,594
-
(21,973)
290,830
(1,792)
24,831
19,466
(6,971)
(30,274)
296,090
28,871
36,728
-
(1,903)
(30,756)
329,030
20,332
168
-
-
-
(2,866)
17,634
124
1,794
-
-
(2,752)
16,800
(132)
-
-
-
(2,436)
14,232
18,040
15,623
15,936
13,688
168,496
238,431
239,589
229,040
(1) Other International includes China and Argentina. We have entered into an agreement to sell our interest in Argentina
effective July 1, 2007. We expect the sale, which is subject to regulatory and partner approvals, to close in 2008. Argentina
crude oil reserves totaled 6,759 MBbls at December 31, 2007.
(2) The increase in total proved reserves includes 6 MMBbl in the US Wattenberg field, primarily due to infill drilling
activities, 3 MMBbl in the deepwater Gulf of Mexico Lorien field and 13 MMBbl in the North Sea Dumbarton field.
Purchase of minerals in place is the result of the Patina Merger. See Note 3—Acquisitions and Divestitures.
(3)
(4) The increase in US proved reserves includes 14 MMBbl in the Wattenberg field, primarily due to infill drilling activities.
(5)
Purchase of minerals in place includes 18 MMBbl acquired in the purchase of U.S. Exploration. See Note 3—Acquisitions
and Divestitures.
Sale of minerals in place is primarily due to the sale of Gulf of Mexico shelf properties. See Note 3—Acquisitions and
Divestitures.
(7) The positive revisions within the US are primarily due to 29 MMBls 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.
(8) The increase in proved reserves includes 17 MMBbl in the US Wattenberg field, primarily due to infill drilling activities, 8
(6)
MMBbl in the deepwater Gulf of Mexico and 10 MMBbl in the North Sea Dumbarton field area.
(9) West Africa production includes sales from the Alba field to the Alba LPG plant of 2,805 MBbls in 2007, 2,931 MBbls in
2006 and 1,183 MBbls in 2005.
96
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:
Year Ended December 31, 2007
Revenues
Production costs (2)
Transportation
E&P corporate
Exploration expense
DD&A
Impairment of operating assets
Accretion expense
Income before income taxes
Income tax expense
Results of operations from producing
activities (excluding corporate
overhead and interest costs)
Our share of Alba Plant's
results of operations from
producing activities
Year Ended December 31, 2006
Revenues
Production costs (2)
Transportation
E&P corporate
Exploration expense
DD&A
Impairment of operating assets
Accretion expense
Income before income taxes
Income tax expense
Results of operations from producing
activities (excluding corporate
overhead and interest costs)
Our share of Alba Plant's
results of operations from
producing activities
Year Ended December 31, 2005
Revenues
Production costs (2)
Transportation
E&P corporate
Exploration expense
DD&A
Impairment of operating assets
Accretion expense
Income (loss) before income taxes
Income tax expense
Results of operations from producing
results of operations from
producing activities
Our share of Alba Plant's
results of operations from producing
activities
United
States
West
Africa
Israel
Ecuador
(in thousands)
North
Sea
Other
Int'l (1)
Total
$
1,952,435
317,984
39,542
31,902
122,339
589,705
3,661
5,969
841,333
191,427
$
405,988
39,222
-
3,309
43,544
24,949
-
109
294,855
83,685
$
113,001
7,711
-
1,687
1,418
17,805
-
450
83,930
14,339
$
35,137
3,203
-
3,193
215
10,353
-
167
18,006
3,582
$
363,886
37,987
10,523
3,572
16,847
79,380
-
1,346
214,231
113,860
$
130,789
44,339
1,634
2,870
2,781
20,413
-
84
58,668
9,713
$
3,001,236
450,446
51,699
46,533
187,144
742,605
3,661
8,125
1,511,023
416,606
$
649,906
$
211,170
$
69,591
$
14,424
$
100,371
$
48,955
$
1,094,417
$
-
$
128,051
$
-
$
-
$
-
$
-
$
128,051
$
1,936,590
338,655
20,729
60,710
113,015
561,948
8,525
8,861
824,147
313,011
$
413,682
26,556
-
4,656
7,329
23,402
-
104
351,635
125,493
$
92,373
9,066
-
111
286
13,911
-
452
68,547
19,810
$
33,575
3,021
-
3,102
228
11,611
-
221
15,392
3,848
$
115,232
11,655
7,010
3,346
10,499
8,045
-
1,159
73,518
42,111
$
143,364
39,596
803
2,118
11,311
25,685
-
-
63,851
23,368
$
2,734,816
428,549
28,542
74,043
142,668
644,602
8,525
10,797
1,397,090
527,641
$
511,136
$
226,142
$
48,737
$
11,544
$
31,407
$
40,483
$
869,449
$
-
$
101,338
$
-
$
-
$
-
$
-
$
101,338
$
1,374,374
216,478
9,350
34,162
130,018
328,645
5,368
9,590
640,763
140,916
$
281,901
30,659
-
435
5,463
26,978
-
51
218,315
76,518
$
65,050
8,504
-
188
223
11,120
-
281
44,734
7,752
$
31,868
3,000
-
2,611
341
12,246
-
158
13,512
3,378
$
123,583
12,503
6,562
2,591
5,985
9,866
-
1,134
84,942
36,834
$
121,514
28,796
852
947
12,680
24,237
-
-
54,002
21,033
$
1,998,290
299,940
16,764
40,934
154,710
413,092
5,368
11,214
1,056,268
286,431
$
499,847
$
141,797
$
36,982
$
10,134
$
48,108
$
32,969
$
769,837
$
-
$
33,916
$
-
$
-
$
-
$
-
$
33,916
(1) Other International includes China, Argentina and Suriname.
(2)
Production costs consist of oil and gas operations expense, production and ad valorem taxes, plus general and
administrative expense supporting oil and gas operations.
97
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Unaudited) (1)
Costs incurred in connection with crude oil and natural gas acquisition, exploration and development are as follows:
United
States
West
Africa
Israel
Ecuador
(in thousands)
North
Sea
Other
Int'l (2)
Total
Year Ended December 31, 2007
Property acquisition costs
Proved
Unproved
Total acquisition costs
Exploration costs
Development costs (4) (5) (6)
Total consolidated operations
Our share of Alba Plant's
development costs
Year Ended December 31, 2006
Property acquisition costs
Proved (3)
Unproved (3)
Total acquisition costs
Exploration costs
Development costs (4) (5)
Total consolidated operations
Our share of Alba Plant's
development costs
Year Ended December 31, 2005
Property acquisition costs
Proved (3)
Unproved (3)
Total acquisition costs
Exploration costs
Development costs (4) (5) (6)
Total consolidated operations
Our share of Alba Plant's
development costs
$
11,239
144,422
155,661
184,412
1,081,221
1,421,294
-
$
-
-
179,043
15,185
194,228
$
-
$
-
-
2,515
24,523
27,038
$
-
$
-
-
215
29
244
$
-
$
-
-
51,564
46,926
98,490
$
-
$
900
900
2,770
22,966
26,636
$
$
$
11,239
145,322
156,561
420,519
1,190,850
1,767,930
$
$
-
$
516
$
-
$
-
$
-
$
-
$
516
$
514,294
157,141
671,435
204,787
784,877
$
7,971
25,500
33,471
13,076
6,933
-
$
1,000
1,000
286
13,869
-
$
-
-
228
48
-
$
831
831
18,185
231,484
-
$
-
-
11,311
21,649
$
522,265
184,472
706,737
247,873
1,058,860
$
1,661,099
$
53,480
$
15,155
$
276
$
250,500
$
32,960
$
2,013,470
$
-
$
580
$
-
$
-
$
-
$
-
$
580
$
2,642,572
1,084,545
3,727,117
164,820
657,858
-
$
-
-
18,126
2,738
-
$
-
-
223
5,928
-
$
-
-
341
(1,660)
-
$
140
140
6,308
19,729
-
$
250
250
12,680
13,858
$
2,642,572
1,084,935
3,727,507
202,498
698,451
$
4,549,795
$
20,864
$
6,151
$
(1,319)
$
26,177
$
26,788
$
4,628,456
$
-
$
27,639
$
-
$
-
$
-
$
-
$
27,639
(1) Costs incurred include capitalized and expensed items.
(2) Other International includes China, Argentina and Suriname.
(3)
Includes amounts allocated from the U.S. Exploration acquisition (2006) and the Patina Merger (2005). See Note 3—
Acquisitions and Divestitures.
(4) US development costs include increases in asset retirement obligations of $24 million in 2007, $4 million in 2006 and
$39 million in 2005. US asset retirement costs of $33 million in 2006 and $66 million in 2005 were incurred as a result of
hurricane damage and are excluded from the costs incurred schedule above as we expected to recover the costs from
insurance proceeds. See Note 4—Effect of Gulf Coast Hurricanes.
(5) Worldwide development costs include amounts spent to develop proved undeveloped reserves of $1.0 billion in 2007,
$768 million in 2006 and $471 million in 2005. Worldwide development costs also include $191 million spent on a floating
production, storage and offloading vessel in the North Sea Dumbarton field in 2006.
(6) North Sea development costs include increases in asset retirement obligations of $4 million in 2007 and $5 million in 2005.
98
Capitalized Costs Relating to Oil and Gas Producing Activities (Unaudited)
Aggregate capitalized costs relating to crude oil and natural gas producing activities, including asset retirement costs
and related accumulated DD&A, are as follows:
Unproved oil and gas properties (1)
Proved oil and gas properties (2)
Total oil and gas properties
Accumulated DD&A
Net capitalized costs
Our share of Alba Plant net capitalized costs
December 31,
2007
2006
(in thousands)
$
1,164,707
$
1,053,254
8,903,163
10,067,870
(2,280,789)
7,787,081
117,212
$
$
7,671,806
8,725,060
(1,707,895)
7,017,165
124,454
$
$
(1) Unproved oil and gas properties includes $628 million and $823 million at December 31, 2007 and 2006, respectively,
remaining from the allocation of costs to unproved properties acquired in the Patina Merger and the acquisition of U.S.
Exploration.
Proved oil and gas properties include asset retirement costs of $91 million and $49 million at December 31, 2007 and 2006,
respectively.
(2)
99
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
(Unaudited)
The following information is based on our best estimate of the required data for the Standardized Measure of
Discounted Future Net Cash Flows as of December 31, 2007, 2006 and 2005 in accordance with SFAS 69. The
standard requires the use of a 10% discount rate. This information is not the fair market value nor does it represent
the expected present value of future cash flows of our proved oil and gas reserves:
December 31, 2007
Future cash inflows (2)
Future production costs (3)
Future development costs
Future income tax expense
Future net cash flows
10% annual discount for
estimated timing of cash flows
Standardized measure of discounted
future net cash flows
December 31, 2006
Future cash inflows (2)
Future production costs (3)
Future development costs
Future income tax expense
Future net cash flows
10% annual discount for
estimated timing of cash flows
Standardized measure of discounted
future net cash flows
December 31, 2005
Future cash inflows (2)
Future production costs (3)
Future development costs
Future income tax expense
Future net cash flows
10% annual discount for
estimated timing of cash flows
Standardized measure of discounted
future net cash flows
United
States
West
Africa
Israel
Ecuador
(in millions)
North
Sea
Other
Int'l (1)
Total
$
30,733
5,936
3,136
6,622
15,039
$
6,935
1,112
202
1,348
4,273
$
858
180
88
146
444
$
704
174
12
115
403
$
2,492
516
200
881
895
$
879
335
15
125
404
$
42,601
8,253
3,653
9,237
21,458
7,398
1,705
163
227
221
93
9,807
$
7,641
$
2,568
$
281
$
176
$
674
$
311
$
11,651
$
18,948
4,551
2,846
3,422
8,129
$
4,904
738
80
1,348
2,738
$
972
146
90
187
549
$
629
162
12
130
325
$
1,225
327
35
435
428
$
808
187
28
177
416
$
27,486
6,111
3,091
5,699
12,585
3,966
1,132
215
170
95
120
5,698
$
4,163
$
1,606
$
334
$
155
$
333
$
296
$
6,887
$
22,931
5,099
1,887
4,645
11,300
$
5,436
556
92
1,589
3,199
$
1,031
154
88
182
607
$
539
47
12
142
338
$
1,267
352
184
381
350
$
868
290
37
159
382
$
32,072
6,498
2,300
7,098
16,176
5,201
1,554
236
162
138
114
7,405
$
6,099
$
1,645
$
371
$
176
$
212
$
268
$
8,771
100
(1) Other International includes China and Argentina. We have entered into an agreement to sell our interest in Argentina
effective July 1, 2007. We expect the sale, which is subject to regulatory and partner approvals, to close in 2008.
Argentina’s standardized measure of discounted future net cash flows totaled $66 million at December 31, 2007.
(2) The standardized measure of discounted future net cash flows for 2007, 2006 and 2005 does not include cash flows relating
(3)
to anticipated future methanol or power sales.
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.
101
Future cash inflows are computed by applying year-end prices, adjusted for location and quality differentials on a
property-by-property basis, to year-end quantities of proved reserves, except in those instances where fixed and
determinable price changes are provided by contractual arrangements at year-end. The discounted future cash flow
estimates do not include the effects of derivative instruments. Average prices per region are as follows:
December 31, 2007
Average crude oil price per Bbl
Average natural gas price per Mcf
December 31, 2006
Average crude oil price per Bbl
Average natural gas price per Mcf
December 31, 2005
Average crude oil price per Bbl
Average natural gas price per Mcf
United
States
West
Africa
Israel
Ecuador
North
Sea
Other
Int'l (1)
Total
$
88.00
6.78
$
81.26
0.27
$
-
2.69
$
-
3.74
$
93.79
7.07
$
61.72
-
$
85.62
4.36
$
57.02
5.32
$
51.49
0.27
$
-
2.70
$
-
3.75
$
57.81
7.11
$
48.04
0.85
$
54.87
3.48
$
58.20
8.59
$
51.62
0.25
$
-
2.62
$
-
3.75
$
58.47
5.39
$
49.23
-
$
55.39
5.16
(1) Other International includes China and Argentina.
We estimate that a $1.00 per Bbl change in the average price of crude oil or a $.10 per Mcf change in the average
price of natural gas from the year-end prices at December 31, 2007 would change the discounted future net cash
flows before income taxes by approximately $176 million or $154 million, respectively.
Future production and development costs, which include dismantlement and restoration expense, are computed by
estimating the expenditures to be incurred in developing and producing the proved crude oil and natural gas reserves
at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions.
Future development costs include amounts that we expect to spend to develop proved undeveloped reserves of
$671 million in 2008, $715 million in 2009 and $408 million in 2010.
Future income tax expense is computed by applying the appropriate year-end statutory tax rates to the estimated
future pretax net cash flows relating to proved crude oil and natural gas reserves, less the tax bases of the properties
involved. Future income tax expense gives effect to tax credits and allowances, but does not reflect the impact of
general and administrative costs and exploration expenses of ongoing operations.
Imbalance receivables and liabilities are as follows:
Imbalance receivables
Imbalance liabilities
2007
Year Ended December 31,
2006
(in thousands)
2005
$
12,640
10,288
$
18,389
16,750
$
18,100
34,600
Imbalance receivables and imbalance liabilities have been excluded from the standardized measure of discounted
future net cash flows.
102
Sources of Changes in Discounted Future Net Cash Flows (Unaudited)
Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to proved
crude oil and natural gas reserves are as follows:
2007
Year Ended December 31,
2006
(in millions)
2005
Standardized measure of discounted future net
cash flows at the beginning of the year
Changes in standardized measure of dicounted future net cash flows:
Sales of oil and gas produced, net of production costs
Net changes in prices and production costs
Extensions, discoveries and improved recovery, less related costs
Changes in estimated future development costs
Development costs incurred during the period
Revisions of previous quantity estimates
Purchases of minerals in place
Sales of minerals in place
Accretion of discount
Net change in income taxes
Change in timing of estimated future production and other
Aggregate change in standardized measure of discounted
future net cash flows
Standardized measure of discounted future net cash flows
at the end of the year
$
6,887
$
8,771
$
3,342
(2,427)
5,266
1,635
(775)
1,189
1,276
6
(95)
1,006
(1,900)
(417)
(2,177)
(2,788)
769
(558)
1,076
(92)
573
(579)
1,274
777
(159)
(1,563)
2,160
1,173
(912)
751
273
4,720
-
519
(2,099)
407
4,764
(1,884)
5,429
$
11,651
$
6,887
$
8,771
103
Supplemental Quarterly Financial Information (Unaudited)
Supplemental quarterly financial information is as follows:
2007 (1)
Revenues
Income before taxes
Net income
Earnings per share:
Basic
Diluted
2006 (2)
Revenues
Income before taxes
Net income
Earnings per share:
Basic
Diluted
Quarter Ended
March 31,
June 30,
September 30, December 31,
Total
(in thousands except per share amounts)
$
742,545
303,852
211,812
$
794,213
293,101
209,105
$
813,811
343,277
222,675
$
921,461
427,337
300,278
$
3,272,030
1,367,567
943,870
1.24
1.22
1.22
1.21
1.30
1.28
1.75
1.73
5.52
5.45
$
711,997
349,353
226,087
$
772,580
(44,865)
(30,705)
$
741,319
544,966
318,064
$
714,186
246,763
164,982
$
2,940,082
1,096,217
678,428
1.28
1.26
(0.17)
(0.17)
1.80
1.75
0.95
0.94
3.86
3.79
(1) First quarter 2007 includes a loss on involuntary conversion of $13 million and second quarter 2007 includes a
loss on involuntary conversion of $38 million. See Note 3—Effect of Gulf Coast Hurricanes.
(2) First quarter 2006 includes a mark-to-market gain of $39 million due to a loss of cash flow hedge accounting
treatment for certain derivative instruments, and a loss of $25 million related to amounts previously recorded in
AOCL due to a delay in the timing of production. Second quarter 2006 includes a loss of $399 million related
to amounts previously recorded in AOCL due to the sale of Gulf of Mexico shelf properties. Third quarter 2006
includes a gain of $204 million from the sale of Gulf of Mexico shelf properties. Fourth quarter 2006 includes
an additional gain of $7 million from the sale of Gulf of Mexico Shelf properties. See Note 3—Acquisitions
and Divestitures and Note 12—Derivative Instruments and Hedging Activities.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed
by us in the reports we file or furnish to the SEC under the Securities Act of 1934, as amended, is recorded,
processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that
information is accumulated and communicated to management, including our principal executive officer and
principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Our principal executive officer and principal financial officer have evaluated the effectiveness of our “disclosure
controls and procedures,” as such term is defined in Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of
1934, as amended, as of the end of the period covered by this Annual Report on Form 10-K. Based upon their
evaluation, they have concluded that our disclosure controls and procedures are effective.
In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and
procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that
the objectives of the control system will be met. In addition, the design of any control system is based in part upon
certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-
benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control
systems, there is only reasonable assurance that our controls will succeed in achieving their goals under all potential
future conditions.
104
Management’s Annual Report on Internal Control over Financial Reporting
The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to
Management’s Report on Internal Control over Financial Reporting, included in Item 8. Financial Statements and
Supplementary Data.
The independent auditor’s attestation report called for by Item 308(b) of Regulation S-K is incorporated herein by
reference to Report of Independent Registered Public Accounting Firm (Internal Control Over Financial Reporting),
included in Item 8. Financial Statements and Supplementary Data.
Changes in Internal Control over Financial Reporting
During the fourth quarter of 2007, we implemented the first phase of a new Enterprise Resource Planning (ERP)
software system to replace our various legacy systems. As appropriate, we modified the design and documentation
of internal control processes and procedures relating to the new system. We believe that the new ERP system has
strengthened and will continue to fortify our internal controls over financial reporting as additional phases are put to
use; however, there are inherent risks in implementing any new system that could impact our financial reporting. See
Item 1A. Risk Factors—Information technology systems implementation issues could disrupt our internal
operations, increase our costs and adversely affect our financial results or our ability to report our financial results.
In the event that issues arise, we have manual procedures in place which would facilitate our continued recording
and reporting of results from the new ERP system. However, because of its inherent limitations, internal control
over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness
to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or
that the degree of compliance with the policies or procedures may deteriorate.
We will continue to monitor, test, and appraise the impact and effect of the new ERP system on our internal controls
and procedures as additional phases and features of the system are implemented. There were no changes in internal
controls over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or
are reasonably likely to materially affect, our internal controls over financial reporting, except as described above.
Item 9B. Other Information.
None.
105
Item 10. Directors, Executive Officers and Corporate Governance.
PART III
The information required by this item is incorporated herein by reference to the 2008 Proxy Statement, which will
be filed with the SEC not later than 120 days subsequent to December 31, 2007.
Item 11. Executive Compensation.
The information required by this item is incorporated herein by reference to the 2008 Proxy Statement, which will
be filed with the SEC not later than 120 days subsequent to December 31, 2007.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters.
The information required by this item is incorporated herein by reference to the 2008 Proxy Statement, which will
be filed with the SEC not later than 120 days subsequent to December 31, 2007.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by this item is incorporated herein by reference to the 2008 Proxy Statement, which will
be filed with the SEC not later than 120 days subsequent to December 31, 2007.
Item 14. Principal Accounting Fees and Services.
The information required by this item is incorporated herein by reference to the 2008 Proxy Statement, which will
be filed with the SEC not later than 120 days subsequent to December 31, 2007.
Item 15. Exhibits, Financial Statements Schedules.
(a) The following documents are filed as a part of this report:
PART IV
(3) Exhibits: The exhibits required to be filed by this Item 15 are set forth in the Index to Exhibits
accompanying this report.
106
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
Date: February 27, 2008
Date: February 27, 2008
Date: February 27, 2008
NOBLE ENERGY, INC.
(Registrant)
By: /s/ Charles D. Davidson
Charles D. Davidson,
Chairman of the Board, President,
Chief Executive Officer and Director
By: /s/ Chris Tong
Chris Tong,
Senior Vice President, Chief Financial Officer
By: /s/ Frederick B. Bruning
Frederick B. Bruning,
Vice President, Chief Accounting Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature
Capacity in which signed
Date
/s/ Charles D. Davidson
Charles D. Davidson
/s/ Chris Tong
Chris Tong
/s/ Frederick B. Bruning
Frederick B. Bruning
/s/ Jeffrey L. Berenson
Jeffrey L. Berenson
/s/ Michael A. Cawley
Michael A. Cawley
/s/ Edward F. Cox
Edward F. Cox
/s/ Thomas J. Edelman
Thomas J. Edelman
Chairman of the Board, President,
Chief Executive Officer and Director
(Principal Executive Officer)
Senior Vice President,
Chief Financial Officer
(Principal Financial Officer)
February 27, 2008
February 27, 2008
Vice President, Chief Accounting Officer
February 27, 2008
(Principal Accounting Officer)
February 27, 2008
February 27, 2008
February 27, 2008
February 27, 2008
Director
Director
Director
Director
107
/s/ Kirby L. Hedrick
Kirby L. Hedrick
/s/ Scott D. Urban
Scott D. Urban
/s/ William T. Van Kleef
William T. Van Kleef
Director
Director
Director
February 27, 2008
February 27, 2008
February 27, 2008
108
Exhibit
Number
INDEX TO EXHIBITS
Exhibit **
3.1
3.2
— Certificate of Incorporation, as amended, of the Registrant as currently in effect (filed as
Exhibit 3.2 to the Registrant’s Annual Report on Form 10-K for the year ended
December 31, 1987 and incorporated herein by reference).
— Composite copy of Bylaws of the Registrant as currently in effect (filed as Exhibit 3.1 to the
Registrant’s Current Report on Form 8-K (Date of Event: January 29, 2002) dated
February 8, 2002 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 *
— Restoration of Retirement Income Plan for Certain Participants in the Noble Energy, Inc.
Retirement Plan dated September 21, 1994, effective as of May 19, 1994 (filed as Exhibit 10.5 to
the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1994 and
incorporated herein by reference).
10.2 *
— Amendment No. 1 to the Restoration of Retirement Income Plan for Certain Participants in the
Noble Affiliates Retirement Plan executed March 26, 2002 (filed as Exhibit 10.2 to the
Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002 and
incorporated herein by reference).
10.3 *
— 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).
10.4 *
— Noble Energy, Inc. Deferred Compensation Plan (formerly known as the Noble Affiliates Thrift
Restoration Plan dated May 9, 1994) as restated effective August 1, 2001 (filed as Exhibit 10.4 to
the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002 and
incorporated herein by reference).
109
Exhibit
Number
Exhibit **
10.5 *
— Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended, dated April 25,
2005, and approved by the stockholders of the Company on April 29, 2003 (filed as Exhibit 10.2
to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 and
incorporated herein by reference).
10.6 *
— 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).
10.7 *
— Form of Restricted Stock Agreement under the Noble Energy, Inc. 1992 Stock Option and
Restricted Stock Plan (filed as Exhibit 10.2 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).
10.8 *
— 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).
10.9 *
10.10*
— Noble Energy, Inc. Non-Employee Director Fee Deferral Plan dated April 25, 2002 and effective
as of April 23, 2002 (filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for
the quarter ended March 31, 2002 and incorporated herein by reference).
— 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).
10.11
— 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).
10.12
— Stock Purchase Agreement dated as of July 1, 1996, between Samedan Oil Corporation and
Enterprise Diversified Holdings Incorporated (filed as Exhibit 2.1 to the Registrant’s Current
Report on Form 8-K (Date of Event: July 31, 1996) dated August 13, 1996 and incorporated
herein by reference).
10.13
— Noble Preferred Stock Remarketing and Registration Rights Agreement dated as of
November 10, 1999 by and among the Registrant, Noble Share Trust, The Chase Manhattan
Bank, and Donaldson, Lufkin & Jenrette Securities Corporation (filed as Exhibit 10.15 to the
Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999 and
incorporated herein by reference).
10.14*
— 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).
10.15*
— Form of Change of Control Agreement entered into between the Registrant and each of the
Registrant’s officers, with schedule setting forth differences in Change of Control Agreements
(filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended
September 30, 2004 and incorporated herein by reference).
10.16
— 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).
110
Exhibit
Number
Exhibit **
10.17
10.18
10.19
10.20
10.21
10.22
10.23
— 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).
— 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).
— 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).
— 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).
— 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).
— 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).
— 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).
10.24*
— Noble Energy, Inc. 2004 Long-Term Incentive Plan effective as of January 1, 2004 (filed as
Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended
June 30, 2004 and incorporated herein by reference).
10.25*
— Form of Performance Units Agreement under the Noble Energy, Inc. 2004 Long-Term Incentive
Program (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).
10.26
— Purchase and Sale Agreement, dated February 7, 2006, among Noble Energy Production, Inc.,
U.S. Exploration Holdings, LLC, U.S. Exploration Holdings, Inc. and United States
Exploration, Inc., filed herewith (filed as Exhibit 10.28 to the Registrant’s Annual Report on
Form 10-K for the year ended December 31, 2005 and incorporated herein by reference).
10.27
— $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).
111
Exhibit
Number
Exhibit **
10.28
10.29*
10.30*
10.31*
— $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).
— Noble Energy, Inc. 2005 Non-Employee Director Fee Deferral Plan, dated December 5, 2005 and
effective as of January 1, 2005 (filed as Exhibit 10.1 to the Registrant’s Current Report on
Form 8-K (Date of Event: December 5, 2005), filed December 8, 2005 and incorporated herein
by reference).
— Amendment No. 1 to the Noble Energy, Inc. Non-Employee Director Fee Deferral Plan, dated
December 5, 2005 and effective as of January 1, 2005 (filed as Exhibit 10.2 to the Registrant’s
Current Report on Form 8-K (Date of Event: December 5, 2005), filed December 8, 2005 and
incorporated herein by reference).
— 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).
10.32*
— 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).
10.33*
— 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).
10.34*
10.35*
— Form of Restricted Stock Agreement under the Noble Energy, Inc. 2005 Non-Employee Director
Stock Plan (filed as Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the
quarter ended June 30, 2005 and incorporated herein by reference).
— 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).
10.36
— Purchase and Sale Agreement dated May 15, 2006 by and between the Company and Coldren
Resources LP (filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the
quarter ended June 30, 2006 and incorporated herein by reference).
10.37*
— Noble Energy, Inc. Change of Control Severance Plan for Executives (filed as Exhibit 10.1 to the
Registrant’s Current Report on Form 8-K (Date of Event: October 24, 2006) filed October 30,
2006 and incorporated herein by reference).
10.38*
— 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).
10.39*
Noble Energy, Inc. 2005 Non-Employee Director Fee Deferral Plan (as amended effective
January 1, 2008) filed herewith.
10.40*
— Noble Energy, Inc. Change of Control Severance Plan for Executives (as amended effective
January 1, 2008) filed herewith.
10.41*
— Noble Energy, Inc. Change of Control Agreement (as amended effective January 1, 2008) filed
herewith.
10.42*
— Noble Energy, Inc. 2004 Long-Term Incentive Plan (as amended effective January 1, 2008) filed
herewith.
112
Exhibit
Number
Exhibit **
10.43*
— Amendment to the 2006 Performance Units Agreement (as amended effective January 1, 2008)
filed herewith.
10.44*
— Noble Energy, Inc. 2005 Deferred Compensation Plan (as amended effective January 1, 2008)
filed herewith.
10.45*
— Noble Energy, Inc. Retirement Restoration Plan (as amended effective December 1, 2007) filed
herewith.
21
— Subsidiaries, filed herewith.
23.1
23.2
23.3
23.4
31.1
— Consent of Independent Registered Public Accounting Firm—KPMG LLP, filed herewith.
— Consent of Independent Registered Public Accounting Firm—PricewaterhouseCoopers LLP,
filed herewith.
— Consent of Independent Registered Public Accounting Firm—UHY LLP, filed herewith.
— Consent of Netherland, Sewell & Associates, Inc., filed herewith.
— 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
99.2
99.3
— Report of Independent Public Accounting Firm—PricewaterhouseCoopers LLP, filed herewith.
— Report of Independent Public Accounting Firm—UHY LLP, filed herewith.
— 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.
113
In this report, the following abbreviations are used:
GLOSSARY
Barrel(s)
Thousand barrels
Bbl(s)
MBbls
MMBbls Million barrels
Barrels per day
Bpd
Barrels oil per day
Bopd
Barrels oil equivalent
Boe
Thousand barrels oil equivalent
MBoe
Million barrels oil equivalent
MMBoe
Barrels oil equivalent per day
Boepd
Thousand gallons
Kgal
Kilowatt
KW
Kilowatt hours
KWh
Megawatt
MW
Thousand cubic feet
Mcf
Million cubic feet
MMcf
Billion cubic feet
Bcf
Trillion cubic feet
Tcf
Mcfpd
Thousand cubic feet per day
MMcfpd Million cubic feet per day
Mcfe
MMcfe
Bcfe
BTU
MMBtu
MMBtupd Million British thermal units per day
Btupcf
MT
MTpd
LNG
LPG
NGL
British thermal unit per cubic foot
Metric tons
Metric tons per day
Liquefied natural gas
Liquefied petroleum gas
Natural gas liquid
Thousand cubic feet equivalent
Million cubic feet equivalent
Billion cubic feet equivalent
British thermal unit
Million British thermal units
114
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DIRECTORS
CHARLES D. DAVIDSON (4)
Chairman of the Board, President and Chief Executive Officer, Noble Energy, Inc.
JEFFREY L. BERENSON (2) (3)
President and Chief Executive Officer, Berenson & Company
MICHAEL A. CAWLEY (1) (3)
Trustee, President and Chief Executive Officer, The Samuel Roberts Noble Foundation, Inc.
EDWARD F. COX (2) (3) (4)
Partner, law firm of Patterson Belknap Webb & Tyler LLP
THOMAS J. EDELMAN (4)
Former Chairman of the Board and Chief Executive Officer, Patina Oil & Gas Corporation
KIRBY L. HEDRICK (2) (3) (4)
Former Executive Vice President, Phillips Petroleum Company
SCOTT D. URBAN (1) (3) (4)
Former Group Vice President, BP
WILLIAM T. VAN KLEEF (1) (3)
Former Executive Vice President and Chief Operating Officer, Tesoro Corporation
COMMITTEE MEMBERSHIP
(1)
(2)
(3)
(4)
Audit Committee
Compensation, Benefits and Stock Options Committee
Corporate Governance and Nominating Committee
Environment, Health and Safety Committee
EXECUTIVE OFFICERS
CHARLES D. DAVIDSON
Chairman of the Board, President, Chief Executive Officer and Director
ALAN R. BULLINGTON
Senior Vice President, International
SUSAN M. CUNNINGHAM
Senior Vice President, Exploration
ARNOLD J. JOHNSON
Vice President, General Counsel and Secretary
A. LEE ROBISON
DAVID L. STOVER
CHRIS TONG
Vice President, Human Resources
Executive Vice President and Chief Operating Officer
Senior Vice President and Chief Financial Officer
CORPORATE INFORMATION
ANNUAL MEETING
The Annual Meeting of Stockholders of Noble Energy, Inc. will be held on Tuesday, April 22,
2008, at 9:30 a.m., Central Time, at the Marriott Woodlands Waterway Hotel and Convention
Center located at 1601 Lake Robbins Drive, The Woodlands, Texas 77380. All stockholders
are cordially invited to attend.
FORM 10-K
The Company’s Annual Report on Form 10-K for the year ended December 31, 2007, as
filed with the Securities and Exchange Commission, is included in this report. Additional
copies are available without charge upon request by writing to Investor Relations, Noble
Energy, Inc., 100 Glenborough Drive, Suite 100, Houston, Texas 77067-3610, via the
Company’s Internet website: http://www.nobleenergyinc.com, or via the Securities
and Exchange Commission’s Internet website: http://www.sec.gov.
FORWARD-LOOKING STATEMENT
This 2007 Annual Report to stockholders contains forward-looking statements based on
expectations, estimates and projections as of the date of this report. These statements by
their nature are subject to risks, uncertainties and assumptions and are influenced by
various factors. As a consequence, actual results may differ materially from those expressed
in the forward-looking statements. For more information, see “Item 1A. Risk Factors.
Disclosure Regarding Forward-Looking Statements” in Noble Energy’s Form 10-K included
in this report.
NOBLE ENERGY, INC.
Corporate Headquarters
100 Glenborough Drive
Suite 100
Houston, Texas 77067-3610
(281) 872.3100
INVESTOR RELATIONS
David Larson
Vice President, Investor Relations
(281) 872.3100
Investor_Relations@nobleenergyinc.com
www.nobleenergyinc.com
INDEPENDENT PUBLIC ACCOUNTANTS
KPMG LLP
TRANSFER AGENT AND REGISTRAR
Wells Fargo Bank N.A.
Shareowner Services
161 North Concord Exchange
South St. Paul, MN 55075-1139
(800) 468.9716
stocktransfer@wellsfargo.com
COMMON STOCK LISTED
NEW YORK STOCK EXCHANGE
Symbol - NBL
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