UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
X
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2002
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission file number: 001-07964
NOBLE ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware
(State of incorporation)
73-0785597
(I.R.S. employer identification number)
350 Glenborough Drive, Suite 100
Houston, Texas
(Address of principal executive offices)
77067
(Zip Code)
(Registrant’s telephone number, including area code)
(281) 872-3100
NOBLE AFFILIATES, INC.
(Registrant’s former name)
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, Inc.
New York Stock Exchange, Inc.
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
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 X
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. X
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes X
No
Aggregate market value of Common Stock held by nonaffiliates as of June 28, 2002: $1,934,000,000.
Number of shares of Common Stock outstanding as of February 27, 2003: 57,384,490.
DOCUMENT INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2003 Annual Meeting of Stockholders to be held on
April 29, 2003, which will be filed with the Securities and Exchange Commission within 120 days after
December 31, 2002, are incorporated by reference into Part III.
TABLE OF CONTENTS
PART I.
Item 1.
Business .......................................................................................................................................
General.........................................................................................................................................
Crude Oil and Natural Gas...........................................................................................................
Exploration, Exploitation and Development Activities.........................................................
Production Activities ............................................................................................................
Acquisitions of Oil and Gas Properties, Leases and Concessions ........................................
Marketing..............................................................................................................................
Regulations and Risks...........................................................................................................
Competition...........................................................................................................................
Unconsolidated Subsidiary ..........................................................................................................
Geographical Data........................................................................................................................
Employees....................................................................................................................................
Available Information ..................................................................................................................
Item 2.
Properties .....................................................................................................................................
Offices..........................................................................................................................................
Crude Oil and Natural Gas...........................................................................................................
1
1
2
2
3
4
4
5
6
7
7
7
7
8
8
8
Item 3.
Legal Proceedings ........................................................................................................................ 16
Item 4.
Submission of Matters to a Vote of Security Holders .................................................................. 16
Executive Officers of the Registrant ............................................................................................ 17
PART II.
Item 5.
Market for Registrant’s Common Equity and Related Stockholder Matters................................ 19
Item 6.
Selected Financial Data................................................................................................................ 22
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations....... 23
Item 7a.
Quantitative and Qualitative Disclosures About Market Risk ..................................................... 32
Item 8.
Financial Statements and Supplementary Data ............................................................................ 36
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure....... 69
PART III.
Item 10.
Directors and Executive Officers of the Registrant...................................................................... 69
Item 11.
Executive Compensation.............................................................................................................. 69
Item 12.
Security Ownership of Certain Beneficial Owners and Management.......................................... 69
Item 13.
Certain Relationships and Related Transactions .......................................................................... 70
Item 14.
Controls and Procedures .............................................................................................................. 70
Item 15.
Financial Statement Schedules, Exhibits and Reports on Form 8-K............................................ 70
ii
Item 1.
Business.
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 7a. Quantitative and Qualitative Disclosures About Market Risk - Cautionary Statement for Purposes of
the Private Securities Litigation Reform Act of 1995 and Other Federal Securities Laws” of this Form 10-K.
General
Noble Energy, Inc. (the “Company” or “Noble Energy”), the successor to Noble Affiliates, Inc., is a Delaware
corporation that has been publicly traded on the New York Stock Exchange for over 20 years. Noble Energy is
principally engaged, directly or through its subsidiaries, in the exploration, production and marketing of crude oil
and natural gas. The Company is noted for its innovative methods of marketing its international gas reserves
through projects such as its methanol plant in Equatorial Guinea and its gas-to-power project in Ecuador.
In this report, unless otherwise indicated or the context otherwise requires, the “Company” or the “Registrant”
refers to Noble Energy, Inc. and its subsidiaries. Effective December 31, 2001, Energy Development Corporation
(“EDC”) was merged into Samedan Oil Corporation (“Samedan”). Effective December 31, 2002, Samedan was
merged into Noble Energy, Inc. Effective December 31, 2002, Noble Trading, Inc. (“NTI”) was merged into Noble
Gas Marketing, Inc. (“NGM”) under the name of Noble Energy Marketing, Inc. (“NEMI”).
As of January 1, 2003, the Company’s wholly-owned subsidiary, NEMI, markets the majority of the Company’s
domestic natural gas as well as third-party natural gas. NEMI also markets a portion of the Company’s domestic
crude oil as well as third-party crude oil. For more information regarding NEMI’s operations, see “Item 1. Business-
-Crude Oil and Natural Gas--Marketing” of this Form 10-K.
In this report, the following abbreviations are used:
Barrel
Barrels
Thousand barrels
Barrels per day
Barrels oil per day
Million barrels
Thousand barrels per day
Million barrels per day
Thousand barrels oil per day
Bbl
Bbls
MBbls
Bpd
Bopd
MMBbl
MBpd
MMBpd
MBopd
MMBopd Million barrels oil per day
BOE
MMBoe
MMBoepd Million barrels oil equivalent per day
$MM
Kwh
MW
MWH
For reporting BOE or Mcfe, one Bbl of oil or condensate is equal to six Mcf of natural gas.
Thousand cubic feet
Thousand cubic feet equivalent
Million cubic feet
Million cubic feet equivalent per day
Million cubic feet per day
Billion cubic feet
Billion cubic feet equivalent
Billion cubic feet equivalent per day
Billion cubic feet per day
Trillion cubic feet
Trillion cubic feet equivalent
British thermal unit
British thermal unit per cubic foot
Million British thermal unit
Mcf
Mcfe
MMcf
MMcfepd
MMcfpd
Bcf
Bcfe
Bcfepd
Bcfpd
Tcf
Tcfe
BTU
BTUpcf
MMBTU
MMBTUpd Million British thermal unit per day
Metric tons per day
MTpd
Liquefied petroleum gas
LPG
Millions of dollars
Kilowatt hour
Megawatt
Megawatt hours
Barrels oil equivalent
Million barrels oil equivalent
1
Crude Oil and Natural Gas
Noble Energy, directly or through its subsidiaries or various arrangements with other companies, explores for,
develops and produces crude oil and natural gas. Exploration activities include geophysical and geological
evaluation and exploratory drilling on properties for which the Company has exploration rights. Noble Energy has
been engaged in the exploration, production and marketing of crude oil and natural gas since 1932. The Company
has exploration, exploitation and production operations domestically and internationally. The domestic areas consist
of: offshore in the Gulf of Mexico and California; the Gulf Coast Region (Louisiana, New Mexico and Texas); the
Mid-Continent Region (Oklahoma and Kansas); and the Rocky Mountain Region (Colorado, Montana, North
Dakota, Wyoming and California). The international areas of operations include Argentina, China, Ecuador,
Equatorial Guinea, the Mediterranean Sea (Israel), the North Sea (Denmark, Netherlands and United Kingdom) and
Vietnam. For more information regarding Noble Energy’s crude oil and natural gas properties, see “Item 2.
Properties--Crude Oil and Natural Gas” of this Form 10-K.
Exploration, Exploitation and Development Activities
Domestic Offshore. Noble Energy has been actively engaged in exploration, exploitation and development of crude
oil and natural gas properties in the Gulf of Mexico (Texas, Louisiana, Mississippi and Alabama) and California
since 1968. The Company has shifted its domestic offshore exploration focus to the Gulf of Mexico deep shelf and
deepwater areas, and away from the Gulf of Mexico’s conventional shallow shelf, in order to take advantage of
lower operating costs, larger prospect sizes and higher rates of return. The Company’s current offshore production is
derived from 194 gross wells operated by Noble Energy and 304 gross wells operated by others. At
December 31, 2002, the Company held offshore federal leases covering 982,733 gross developed acres and 764,682
gross undeveloped acres on which the Company currently intends to conduct future exploration activities. For more
information, see “Item 2. Properties--Crude Oil and Natural Gas” of this Form 10-K.
Domestic Onshore. Noble Energy has been actively engaged in exploration, exploitation and development of crude
oil and natural gas properties in three regions since the 1930s. The Gulf Coast Region covers onshore Louisiana,
New Mexico and Texas. The Mid-Continent Region covers Oklahoma and Kansas. Properties in the Rocky
Mountain Region are located in Colorado, Montana, North Dakota, Wyoming and California.
Noble Energy’s current onshore production is derived from 1,496 gross wells operated by the Company and 1,238
gross wells operated by others. At December 31, 2002, the Company held 685,162 gross developed acres and
398,815 gross undeveloped acres onshore on which the Company may conduct future exploration activities. For
more information, see “Item 2. Properties--Crude Oil and Natural Gas” of this Form 10-K.
Argentina. Noble Energy has been actively engaged in exploration, exploitation and development of crude oil and
natural gas properties in Argentina since 1996. The Company’s producing properties are located in southern
Argentina in the El Tordillo field, which is characterized by secondary recovery crude oil production from a 10,000
acre reservoir. At December 31, 2002, the Company held 28,988 gross developed acres and 2,398,970 gross
undeveloped acres in Argentina on which the Company may conduct future exploration activities. For more
information, see “Item 2. Properties--Crude Oil and Natural Gas” of this Form 10-K.
China. Noble Energy has been actively engaged in exploration, exploitation and development of crude oil and
natural gas properties in China since 1996. The Company has two concessions offshore China. These concessions,
Cheng Dao Xi and Cheng Zi Kou, are contiguous and adjoin non-owned production in the southern portion of
Bohai Bay. At December 31, 2002, the Company held 7,413 gross developed acres and 2,569,522 gross
undeveloped acres in China on which the Company may conduct future exploration activities. For more
information, see “Item 2. Properties--Crude Oil and Natural Gas” of this Form 10-K.
2
Ecuador. Noble Energy has been actively engaged in exploration, exploitation and development of crude oil and
natural gas properties in Ecuador since 1996. The Company is currently utilizing the gas in the Amistad gas field
(offshore Ecuador), which was discovered in the 1970s, to generate electricity through its 100 percent owned
natural gas-fired power plant, located near the city of Machala. Currently generating 130 MW, with additional
capital investment, the power plant will ultimately be capable of generating 220 MW of electricity into the
Ecuadorian power grid. The concession covers 12,355 gross developed acres and 851,771 gross undeveloped acres
encompassing the Amistad field. For more information, see “Item 2. Properties--Crude Oil and Natural Gas” of this
Form 10-K.
Equatorial Guinea. Noble Energy has been actively engaged in exploration, exploitation and development of crude
oil and natural gas properties offshore Equatorial Guinea (West Africa) since 1990. The offshore Equatorial Guinea
production is from the Alba field, which produces natural gas and condensate. The majority of the natural gas
production is sold to a methanol plant, which began production in the second quarter of 2001. The methanol plant
has a 25-year contract to purchase natural gas from the Alba field. The plant is owned by Atlantic Methanol
Production Company LLC (“AMPCO”), in which the Company indirectly owns a 45 percent interest through its
ownership of Atlantic Methanol Capital Company (“AMCCO”). For more information on the methanol plant, see
“Item 1. Business--Unconsolidated Subsidiary” of this Form 10-K.
At December 31, 2002, the Company held 45,203 gross developed acres and 266,754 gross undeveloped acres
offshore Equatorial Guinea on which the Company may conduct future exploration activities. For more information,
see “Item 2. Properties--Crude Oil and Natural Gas” of this Form 10-K.
Israel. Noble Energy has been actively engaged in exploration, exploitation and development of crude oil and
natural gas properties in the Mediterranean Sea, offshore Israel, since 1998. The Company owns a 47 percent
interest in 11 licenses and two leases. At December 31, 2002, the Company held 123,552 gross developed acres and
1,028,796 gross undeveloped acres located about 20 miles offshore Israel in water depths ranging from 700 feet to
5,000 feet. Noble Energy and its partners announced on June 25, 2002 they had executed a definitive agreement for
the sale of natural gas to Israel Electric Corporation (“IEC”). For more information, see “Item 2. Properties--Crude
Oil and Natural Gas” of this Form 10-K.
North Sea. Noble Energy has been actively engaged in exploration, exploitation and development of crude oil and
natural gas properties in the North Sea (Denmark, Netherlands and United Kingdom) since 1996. At
December 31, 2002, the Company held 81,675 gross developed acres and 677,029 gross undeveloped acres on
which the Company may conduct future exploration activities. For more information, see “Item 2. Properties--
Crude Oil and Natural Gas” of this Form 10-K.
Vietnam. Noble Energy owns a 77 percent interest in two offshore blocks totaling 1,701,812 gross undeveloped
acres in the Nam Con Son Basin. For more information, see “Item 2. Properties--Crude Oil and Natural Gas” of this
Form 10-K.
Production Activities
Operated Property Statistics. The percentage of crude oil and natural gas wells operated and the percentage of sales
volume from operated properties are shown in the following table as of December 31:
(in percentages)
Operated well count basis
Operated sales volume basis
2002
2001
2000
Oil
23.3
29.3
Gas
62.8
45.1
Oil
24.8
37.2
Gas
60.6
52.3
Oil
23.1
48.3
Gas
66.0
64.5
3
Net Production. The following table sets forth Noble Energy’s net crude oil and natural gas production, including
royalty, for the three years ended December 31:
Crude Oil Production (MMBbl)
Natural Gas Production (Bcf)
2002
12.4
141.5
2001
11.2
154.2
2000
9.4
148.7
Crude Oil and Natural Gas Equivalents. The following table sets forth Noble Energy’s net production stated in crude
oil and natural gas equivalent volumes, for the three years ended December 31:
Total Crude Oil Equivalents (MMBoe)
Total Natural Gas Equivalents (Bcfe)
2002
36.0
216.0
2001
36.9
221.3
2000
34.2
205.4
Acquisitions of Oil and Gas Properties, Leases and Concessions
`
During 2002, Noble Energy spent approximately $8 million on the purchase of proved crude oil and natural gas
properties. The Company spent approximately $98 million in 2001 and $99 million in 2000 on proved properties.
For more information, see “Item 2. Properties--Crude Oil and Natural Gas” of this Form 10-K.
During 2002, Noble Energy spent approximately $31 million on acquisitions of unproved properties. The Company
spent approximately $81 million in 2001 and $18 million in 2000 on acquisitions of unproved properties. These
properties were acquired primarily through various offshore lease sales, domestic onshore lease acquisitions and
international concession negotiations. For more information, see “Item 2. Properties--Crude Oil and Natural Gas”
of this Form 10-K.
Marketing
NEMI seeks opportunities to enhance the value of the Company’s domestic natural gas by marketing directly to end
users and aggregating gas to be sold to natural gas marketers and pipelines. During 2002, approximately 83 percent
of NEMI’s total sales were to end users. NEMI is also actively involved in the purchase and sale of natural gas from
other producers. Such third-party natural gas may be purchased from non-operators who own working interests in
the Company’s wells or from other producers’ properties in which the Company may not own an interest. NEMI,
through its wholly-owned subsidiary, Noble Gas Pipeline, Inc., engages in the installation, purchase and operation
of natural gas gathering systems.
Noble Energy has a short-term natural gas sales contract with NEMI, whereby the Company is paid an index price
for all natural gas sold to NEMI. The Company sold approximately 66 percent of its natural gas production to NEMI
in 2002. Third-party sales, including derivative transactions, are recorded as gathering, marketing and processing
revenues. NEMI records the amount paid to Noble Energy and third parties as gathering, marketing and processing
costs and expenses. All intercompany sales and expenses are eliminated in the Company’s consolidated financial
statements. The Company has a small number of long-term natural gas contracts representing less than four percent
of its total natural gas sales.
Crude oil produced by the Company is sold to purchasers in the United States and foreign locations at various prices
depending on the location and quality of the crude oil. The Company has no long-term contracts with purchasers of
its crude oil production. Crude oil and condensate are distributed through pipelines and by trucks to gatherers,
transportation companies and end users. NEMI markets approximately 30 percent of the Company’s crude oil
production as well as certain third-party crude oil. The Company records all of NEMI’s sales as gathering,
marketing and processing revenues and records cost of sales in gathering, marketing and processing costs. All
intercompany sales and expenses are eliminated in the Company’s consolidated financial statements.
4
Crude oil prices are affected by a variety of factors that are beyond the control of the Company. The Company’s
average crude oil price increased $.68 from $23.30 per Bbl in 2001 to $23.98 per Bbl in 2002. Due to the volatility
of crude oil prices, the Company, from time to time, has used hedging instruments and may do so in the future as a
means of controlling its exposure to price changes. For additional information, see “Item 7a. Quantitative and
Qualitative Disclosures About Market Risk” and “Item 8. Financial Statements and Supplementary Data” of this
Form 10-K.
Substantial competition in the natural gas marketplace continued in 2002. The Company’s average natural gas price
decreased from $3.98 per Mcf in 2001 to $2.92 per Mcf in 2002. Due to the volatility of natural gas prices, the
Company, from time to time, has used hedging instruments and may do so in the future as a means of controlling its
exposure to price changes. For additional information, see “Item 7a. Quantitative and Qualitative Disclosures About
Market Risk” and “Item 8. Financial Statements and Supplementary Data” of this Form 10-K.
The largest single non-affiliated purchaser of the Company’s crude oil production in 2002 accounted for
approximately 15 percent of the Company’s crude oil sales, representing approximately three percent of total
revenues. The five largest purchasers accounted for approximately 50 percent of total crude oil sales. The largest
single non-affiliated purchaser of the Company’s natural gas production in 2002 accounted for approximately six
percent of its natural gas sales, representing approximately two percent of total revenues. The five largest purchasers
accounted for approximately 16 percent of total natural gas sales. The Company does not believe that its loss of a
major crude oil or natural gas purchaser would have a material effect on the Company.
Regulations and Risks
General. Exploration for and production and sale of crude oil and natural gas are extensively regulated at the
international, national, 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 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. Noble Energy’s 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 United States 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 its costs of doing business and
consequently affects the Company’s profitability.
Certain Risks. In the Company’s exploration operations, losses may occur before any accumulation of crude oil or
natural gas is found. If crude oil or natural gas is discovered, no assurance can be given that sufficient reserves will
be developed to enable the Company to recover the costs incurred in obtaining the reserves or that reserves will be
developed at a sufficient rate to replace reserves currently being produced and sold. The Company’s international
operations are also subject to certain political, economic and other uncertainties including, among others, risk of
war, expropriation, renegotiation or modification of existing contracts, taxation policies, foreign exchange
restrictions, international monetary fluctuations and other hazards arising out of foreign governmental sovereignty
over areas in which the Company conducts operations.
Environmental Matters. As a developer, owner and operator of crude oil and natural gas properties, the Company is
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. The unauthorized release or discharge of crude oil or certain other
regulated substances from the Company’s domestic onshore or offshore facilities could subject the Company to
5
liability under federal laws and regulations, including the Oil Pollution Act of 1990, the Outer Continental Shelf
Lands Act and the Federal Water Pollution Control Act, as amended. These laws, among others, impose liability for
such a release or discharge for pollution cleanup costs, damage to natural resources and the environment, various
forms of direct and indirect economic losses, civil or criminal penalties, and orders or injunctions, including those
that can require the suspension or cessation of operations causing or impacting or potentially impacting such release
or discharge. The liability under these laws for a substantial such release or discharge, subject to certain specified
limitations on liability, may be extraordinarily large. If any pollution was caused by willful misconduct, willful
negligence or gross negligence within the privity and knowledge of the Company, or was caused primarily by a
violation of federal regulations, the Federal Water Pollution Control Act provides that such limitations on liability
do not apply. Certain of the Company’s facilities are subject to regulations that require the preparation and
implementation of spill prevention control and countermeasure plans relating to the prevention of, and preparation
for, the possible discharge of crude oil into navigable waters.
The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also
known as “Superfund,” imposes liability on certain classes of persons that generated a hazardous substance that has
been released into the environment or that own or operate facilities or vessels onto or into which hazardous
substances are disposed. The Resource Conservation and Recovery Act, as amended, (“RCRA”) and regulations
promulgated thereunder, regulate hazardous waste, including its generation, treatment, storage and disposal.
CERCLA currently exempts crude oil, and RCRA currently exempts certain crude oil and natural gas exploration
and production drilling materials, such as drilling fluids and produced waters, from the definitions of hazardous
substance and hazardous waste, respectively. The Company’s operations, however, may involve the use or handling
of other materials that may be classified as hazardous substances and hazardous wastes, and therefore, these statutes
and regulations promulgated under them would apply to the Company’s generation, handling and disposal of these
materials. In addition, there can be no assurance that such exemptions will be preserved in future amendments of
such acts, if any, or that more stringent laws and regulations protecting the environment will not be adopted.
Certain of the Company’s facilities may also be subject to other federal environmental laws and regulations,
including the Clean Air Act with respect to emissions of air pollutants.
Certain state or local laws or regulations and common law may impose liabilities in addition to, or restrictions more
stringent than, those described herein.
The environmental laws, rules and regulations of foreign countries are generally less stringent than those of the
United States, and therefore, the requirements of such jurisdictions do not generally impose an additional
compliance burden on the Company or on its subsidiaries.
The Company has made and will continue to make expenditures in its efforts to comply with environmental
requirements. The Company does not believe that it has to date expended material amounts in connection with such
activities or that compliance with such requirements will have a material adverse effect upon the capital
expenditures, earnings or competitive position of the Company. Although such requirements do have a substantial
impact upon the energy industry, generally they do not appear to affect the Company any differently or to any
greater or lesser extent than other companies in the industry.
Insurance. The Company has various types of insurance coverages as are customary in the industry which include,
in various degrees, general liability, well control, pollution and physical damage insurance. The Company believes
the coverages and types of insurance are adequate.
Competition
The oil and gas industry is highly competitive. Many companies and individuals are engaged in exploring for crude
oil and natural gas and acquiring crude oil and natural gas properties, resulting in a high degree of competition for
6
desirable exploratory and producing properties exists. A number of the companies with which the Company
competes are larger and have greater financial resources than the Company.
The availability of a ready market for the Company’s crude oil and natural gas production depends on numerous
factors beyond its control, including the level of consumer demand, the extent of worldwide crude oil and natural
gas production, the costs and availability of alternative fuels, the costs and proximity of pipelines and other
transportation facilities, regulation by state and federal authorities and the costs of complying with applicable
environmental regulations.
Unconsolidated Subsidiary
Prior to January 2002, AMCCO was a 50 percent owned joint venture that owned an indirect 90 percent interest in
AMPCO, which completed construction of a methanol plant in Equatorial Guinea in the second quarter of 2001.
During 1999, AMCCO issued $125 million Series A-1 and $125 million Series A-2 senior secured notes due
December 15, 2004 to fund the remaining construction payments. On January 2, 2002, the Company’s partner in
AMCCO directed AMCCO to sell 50 percent of its interest in AMPCO as a component of the partner’s sale of its
Equatorial Guinea assets. The proceeds of the AMPCO sale were used to repay in full AMCCO’s $125 million
Series A-1 Notes on January 28, 2002 and to make a distribution to the Company’s partner. Since the Company’s
partner in AMCCO no longer retains an economic interest in AMPCO, the Company began consolidating AMCCO’s
debt in 2002, thereby including the $125 million Series A-2 Notes in the Company’s balance sheet effective
January 28, 2002. The terms of the $125 million Series A-2 Notes remain unchanged.
The plant construction started during 1998 and initial production of commercial grade methanol commenced
May 2, 2001. The total construction costs of the plant and supporting facilities as of December 31, 2002 were $417
million, with the Company responsible for $208.5 million. The plant is designed to produce 2,500 MTpd of
methanol, which equates to approximately 20,000 Bpd. At this level of production, the plant would purchase
approximately 125 MMcfpd from the 34 percent owned Alba field. The methanol plant has a 25-year contract to
purchase natural gas from the Alba field. For more information, see “Item 7. Management’s Discussion and
Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary
Data--Note 9 - Unconsolidated Subsidiary” of this Form 10-K.
Geographical Data
The Company has operations throughout the world and manages its operations by country. Information is grouped
into five components that are all primarily in the business of natural gas and crude oil exploration, exploitation and
production: United States, Equatorial Guinea, Mediterranean Sea, North Sea and Other International. For more
information, see “Item 8. Financial Statements and Supplementary Data--Note 11 - Geographical Data” of this
Form 10-K.
Employees
The total number of employees of the Company increased during the year from 610 at December 31, 2001, to 624 at
December 31, 2002. Eighty foreign nationals worked in Noble Energy offices in China, Ecuador, Israel and Vietnam
as of December 31, 2002.
Available Information
The Company’s website address is www.nobleenergyinc.com. Available on this website under “Investor Relations -
Investor Relations Menu - SEC Filings,” free of charge, are Noble Energy’s annual reports on Form 10-K, quarterly
reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably
practicable after such materials are electronically filed with or furnished to the United States Securities and
Exchange Commission (“SEC”).
7
Item 2.
Properties.
Offices
The principal corporate office of the Registrant is located in Houston, Texas. The Company maintains offices for
international, domestic onshore and domestic offshore operations in Houston, Texas. The Company also maintains
offices in China, Ecuador, Israel, the United Kingdom and Vietnam. NEMI’s office is located in Houston, Texas.
The Company also maintains offices in Ardmore, Oklahoma for centralized accounting, division orders, employee
benefits and related administrative functions.
Crude Oil and Natural Gas
The Company, directly or through its subsidiaries or various arrangements with other companies, searches for
potential crude oil and natural gas properties, seeks to acquire exploration rights in areas of interest and conducts
exploratory activities. These activities include geophysical and geological evaluation and exploratory drilling, where
appropriate, on properties for which it acquired exploration rights. During 2002, Noble Energy drilled or
participated in the drilling of 194 gross (90.0 net) wells, comprised of 59 gross (16.1 net) international wells and
135 gross (73.9 net) domestic wells. For more information regarding Noble Energy’s oil and gas properties, see
“Item 1. Business--Crude Oil and Natural Gas” of this Form 10-K.
Domestic Offshore. Noble Energy’s first operated commercial deepwater natural gas discovery in East Breaks 421
(Lost Ark) commenced production ahead of schedule in the second quarter of 2002. Production began at an initial
rate of 40 MMcfpd. Noble Energy has a 48 percent working interest in Lost Ark.
Another deepwater natural gas discovery, Green Canyon 136 A-8 (Shasta), commenced production in January 2003
at 25 MMcfpd. Noble Energy has a 25 percent working interest in Shasta.
Green Canyon 282 (Boris), a deepwater crude oil discovery, commenced production from its first well during the
first quarter of 2003 at 9,500 Bopd. The second well is expected to commence production by mid-year 2003 at an
additional 8,000 Bopd. Noble Energy has a 25 percent working interest in Boris.
Another deepwater crude oil discovery, Viosca Knoll 917/961/962 (Swordfish), is expected to commence
production during 2004.
Highlights of the 2002 deep shelf program include several key properties. In the first quarter, Eugene Island 97 #3
(Thunderbolt), in which the Company has a 25 percent working interest, commenced production at 15 MMcfpd.
During the second quarter, Main Pass 108 B-3 commenced production at 15 MMcfpd, and Viosca Knoll 68 #4
commenced production at 16 MMcfpd. The Company has a 25 percent and 30 percent working interest in these
wells, respectively. Noble Energy has a 31 percent working interest in Ship Shoal 225 #1 that commenced
production in the third quarter at 750 Bopd. During the fourth quarter, production of 36 MMcfpd commenced from
the Viosca Knoll 384 A-1 and A-2. Noble Energy has a 24 percent working interest in these wells.
During 2002, the Company expensed eight exploratory wells related to its offshore activity.
Noble Energy was the successful bidder, alone or with partners, on 17 of 20 lease blocks at the Central Gulf of
Mexico Outer Continental Shelf Sale 182. Fifteen of the Company’s 17 bids were approved with two being rejected.
Of the 15 approved bids, nine were on blocks in deepwater, five were on blocks in the deep shelf, and the remaining
block was in the conventional shelf. Approved bids totaled approximately $9.2 million net to the Company’s
interest. Noble Energy will be the designated operator on 12 of the blocks.
8
Domestic Onshore. During the fourth quarter of 2001, Noble Energy acquired all of the Gulf Coast onshore
producing properties of Aspect Energy. As part of the transaction, Noble Energy and Aspect Energy established a
joint venture to explore for and produce crude oil and natural gas. The area of mutual interest extends from
Matagorda County, Texas to Lafayette Parish, Louisiana and includes 7,250 square miles of 3D seismic. This
extensive 3D seismic database enhances Noble Energy’s long-term domestic onshore position by providing a
significant number of future exploration opportunities. During 2002, the joint venture drilled 45 wells, of which 26
wells, or 58 percent, were successful.
During the second quarter of 2002, the Company acquired an interest in the Bendito project in Matagorda County,
Texas. The acquisition consisted of five producing wells in which Noble Energy owns a 35 percent working interest,
3,000 gross developed acres, 8,100 gross undeveloped acres, multiple 3D seismic defined prospects and a license to
45 square miles of proprietary 3D seismic data. The Steele #1, in which the Company owns a 29 percent working
interest, was the initial exploratory test well in the Lower Frio trend of the Bendito project, drilled in late 2002 and
tested at 5.1 MMcfpd and 310 Bopd.
Another domestic onshore exploration project in 2002 was Wildcat Ridge, which includes a 120 square mile
proprietary 3D seismic survey in southeast Texas and southwest Louisiana. Initial drilling commenced in late 2002
with the Doornbos #1, in which Noble Energy owns a 35 percent working interest, discovering Miocene reserves in
multiple zones. The W&T Offshore #1, in which the Company owns a 38 percent working interest, spud in January
2003, is the second successful well within the project. An additional well, the Noble Heirs #1, in which the
Company owns a 38 percent working interest, commenced drilling in February 2003. In addition, technical analysis
continues on several other identified prospects within the Wildcat Ridge project area.
During 2002, the Company expensed 24 exploratory wells related to its onshore activity.
Argentina. Noble Energy participated with a 13 percent working interest in 37 exploitation wells in the El Tordillo
field during 2002. The Company has been awarded, and is awaiting final government approval of, a crude oil and
natural gas exploration permit of approximately 1.2 million acres. The permit is located in the Cuyo Basin of
Mendoza Province in western Argentina. The Company was the successful bidder on an adjacent permit of
approximately 1.1 million acres.
China. Noble Energy completed its development of the Cheng Dao Xi (CDX) field in December 2002. The
Company has a 57 percent working interest in CDX, which is located on the south side of Bohai Bay off the coast of
China. Initial production of 6,000 Bopd (3,420 Bopd net to Noble Energy) from CDX commenced on
January 13, 2003. The facilities on CDX have production capacity of 10,000 Bopd.
During 2002, the Company expensed three exploratory wells related to its activity in China. In early February 2003,
an exploratory well in the South China Sea commenced drilling, with the Company having a 50 percent working
interest.
Ecuador. In September 2002, Noble Energy commenced operations of its 100 percent owned fully integrated
gas-to-power project ahead of schedule. The project includes the Amistad field, which is located in the shallow
waters of the Gulf of Guayaquil near the coast of Ecuador. To date, Noble Energy has completed three development
wells in the Amistad field that supply approximately 30 MMcfpd of natural gas to the Machala power plant. The
power plant is located on the coast near Machala, Ecuador and connects to the Amistad field via a 40-mile pipeline.
Machala Power is the only natural gas-fired commercial power generator in Ecuador. The Machala power plant
currently has generating capacity of 130 MW from twin General Electric Frame 6Fa turbines.
Equatorial Guinea. During 2002, Noble Energy and its partners obtained approval from the government of
Equatorial Guinea for phases 2A and 2B Alba field expansion projects. Phase 2A, which is scheduled to be
9
completed in the fourth quarter of 2003, is expected to increase gross condensate production by approximately
29,000 Bopd (8,900 Bopd net to Noble Energy).
Phase 2B, which is scheduled to be completed during the fourth quarter of 2004, is expected to increase gross
production of LPG by approximately 14,000 Bpd (3,900 Bpd net to Noble Energy) and gross condensate production
by approximately 6,000 Bopd (1,700 Bopd net to Noble Energy). The project includes increasing processing
capacity, storage and offloading facilities at the existing LPG plant. A fractionation unit will also be installed.
Following the completion of phases 2A and 2B, gross condensate and LPG capacity will be approximately 54,000
Bopd (16,000 Bopd net to Noble Energy) and 16,000 Bpd (4,500 Bpd net to Noble Energy), respectively.
Noble Energy holds a 34 percent working interest in the Alba field and related condensate production facilities, a 28
percent working interest in the Bioko Island LPG plant and a 45 percent working interest in the AMPCO plant that
purchases and processes approximately 125 MMcfpd of natural gas into 2,500 MTpd of methanol. During 2002, 17
shipments of methanol were delivered, eight to European markets and nine to markets in the United States.
Israel. The Company and its partners signed a definitive agreement to provide approximately 170 MMcfpd of
natural gas for use in IEC’s power plants. Natural gas will be produced from the Mari-B field, offshore Israel, which
was discovered in 2000. Production is anticipated to begin during the fourth quarter of 2003. Noble Energy has a 47
percent working interest in the project.
North Sea. The Company continued to focus on production and exploration growth in 2002. Two new licenses
(P1047 and P1041) were awarded to Noble Energy in 2002 from the United Kingdom’s 20th Licenses Bid Round.
The Company expects to participate in five exploration wells in 2003, including the Company-operated Joppa
prospect.
Vietnam. The Company continues to evaluate prospects in the two blocks of the Nam Con Son Basin in order to
supplement the Swan discovery well of 2001. During 2002, the Company expensed one exploratory well.
10
Net Exploratory and Developmental Wells. The following table sets forth, for each of the last three years, the
number of net exploratory and development wells drilled by or on behalf of Noble Energy. 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 following table 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.
Net Exploratory Wells
Net Development Wells
Productive(1)
Dry(2)
Productive(1)
Dry(2)
Year Ended
December 31, U.S.
9.78
2002
4.87
2001
17.86
2000
Int’l
.63
3.94
U.S.
11.45
10.79
10.59
Int’l
3.27
5.41
1.00
U.S.
41.53
68.30
101.89
Int’l
12.84
13.67
5.99
U.S.
11.17
12.88
4.17
Int’l
1.62
.57
(1) A productive well is an exploratory or a development well that is not a dry hole.
(2) A dry hole is an exploratory or development well found to be incapable of producing either crude oil or
natural gas in sufficient quantities to justify completion as an oil or gas well.
At January 31, 2003, Noble Energy was drilling 5 gross (2.3 net) exploratory wells and 5 gross (.8 net) development
wells. These wells are located onshore in Louisiana, Wyoming and Argentina and offshore in the Gulf of Mexico
and Equatorial Guinea. These wells have objectives ranging from approximately 5,110 feet to 14,075 feet. The
drilling cost to Noble Energy of these wells will be approximately $7 million if all are dry and approximately $11
million if all are completed as producing wells.
11
Crude Oil and Natural Gas Wells. The number of productive crude oil and natural gas wells in which Noble Energy
held an interest as of December 31 follows:
Crude Oil Wells
United States – Onshore
United States – Offshore
International
Total
Natural Gas Wells
United States – Onshore
United States – Offshore
International
Total
2002(1)(2)
2001(1)(2)
2000(1)(2)
Gross
Net
Gross
Net
Gross
Net
1,131.0
232.5
687.0
2,050.5
1,603.0
265.5
42.0
1,910.5
458.7
95.7
81.3
635.7
1,006.6
184.9
13.1
1,204.6
1,364.5
212.5
670.0
2,247.0
1,673.5
333.5
38.0
2,045.0
573.6
120.0
75.7
769.3
1,025.7
143.3
8.4
1,177.4
1,341.5
210.5
604.0
2,156.0
1,532.5
300.5
31.0
1,864.0
564.0
119.2
66.2
749.4
947.1
133.4
3.5
1,084.0
(1) 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.
(2) One or more completions in the same borehole are counted as one well in this table.
The following table summarizes multiple completions and non-producing wells as of December 31 for the years
shown. Included in wells not producing are productive wells awaiting additional action, pipeline connections or
shut-in for various reasons.
Multiple Completions
Crude Oil
Natural Gas
Not Producing (Shut-in)
Crude Oil
Natural Gas
2002
2001
2000
Gross
Net
Gross
Net
Gross
12.0
28.5
6.0
8.9
13.5
36.5
6.9
14.0
13.5
36.5
Net
6.9
14.0
565.0
121.0
212.3
73.0
391.0
100.0
179.2
36.3
386.0
62.0
177.5
20.6
At year-end 2002, Noble Energy had less than eight percent of its crude oil and natural gas sales volumes committed
to long-term supply contracts and had no similar agreements with foreign governments or authorities.
Since January 1, 2002, 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”). Noble
Energy files Form 23, including reserve and other information, with the EIA.
12
Average Sales Price. The following table sets forth, for each of the last three years, the average sales price per unit
of crude oil produced and per unit of natural gas produced, and the average production cost per unit.
Average sales price per Bbl of crude oil (1):
Year Ended December 31,
2001
2002
2000
United States
International
$23.08
$24.98
$22.88
$23.98
$23.75
$28.28
Combined (2)
$23.98
$23.30
$24.95
Average sales price per Mcf of natural gas (1):
United States
International
$ 3.20
$ 1.18
$ 4.24
$ 1.60
$ 3.90
$ 2.45
Combined (3)
$ 2.92
$ 3.98
$ 3.80
Average production (lifting) cost per Mcfe:
United States
International
Combined
$
$
.70
.79
$
$
.66
.46
$
$
.59
.64
$
.70
$
.60
$
.59
(1) Net production amounts used in this calculation include royalties.
(2) Reflects a reduction of $.02 per Bbl in 2002 and $2.92 per Bbl in 2000 from hedging in the United States.
(3) Reflects an increase of $.04 per Mcf in 2002 and $.03 per Mcf in 2001 from hedging in the United States.
13
Significant Offshore Undeveloped Lease Holdings (interests rounded to nearest whole percent)
Net Working
Interest (%)
Net Working
Interest (%)
Block
East Breaks
279 *
420 *
464 *
465 *
475 *
510 *
519 *
563 *
Green Canyon
23
27
85 *
142
185 *
186 *
187 *
227 *
228 *
303 *
507 *
723 *
724 *
768 *
955 *
958 *
West Cameron
136
392
393
400
419
422
438
443
446
Mustang Island
829
830
Net Working
Interest (%)
33
48
48
48
100
33
100
100
100
43
50
100
100
100
100
100
100
40
50
100
100
100
7
25
40
100
100
100
100
50
100
100
100
80
80
Block
Vermilion
195
207
208
228
230
232
235
280
285
300
353
377
391
Garden Banks
25
154
751 *
795 *
841 *
Main Pass
107
109
110
192
East Cameron
342
348
355
South Timbalier
62
98
156
278
315
Ship Shoal
73
25
25
25
100
100
50
100
50
100
50
100
100
100
50
100
100
100
39
25
25
25
100
67
30
100
100
50
67
50
40
50
Block
Galveston
249-L
250-L
274-L
275-L
277-L
340-S
341-S
South Marsh Island
38
64
70
145
167
195
Mississippi Canyon
26 *
70 *
71 *
123 *
159 *
204 *
524 *
583 *
595 *
602 *
639 *
665 *
769 *
811 *
837 *
849 *
855 *
856 *
857 *
896 *
900 *
901 *
911 *
999 *
1000 *
50
50
50
50
50
50
50
100
67
50
100
100
50
75
75
75
75
75
100
50
50
24
75
24
50
100
30
40
34
30
30
30
67
30
30
40
30
30
*Located in water deeper
than 1,000 feet.
14
Block
Brazos
308-L
336-L
337-L
368-L
543
Ewing Bank
834
949
993
995
996
Eugene Island
96
317
High Island
A-218
A-230
A-426
A-435
A-516
Viosca Knoll
23
344
383
697
820
864 *
908 *
917 *
961 *
962 *
Atwater Valley
10 *
11 *
23 *
66 *
67 *
327 *
533 *
Net Working
Interest (%)
50
50
50
25
100
14
52
98
43
43
25
67
100
100
33
33
100
100
100
24
50
50
35
100
10
10
10
100
100
100
100
100
79
40
The developed and undeveloped acreage (including both leases and concessions) that Noble Energy held as of
December 31, 2002, is as follows:
Location
United States Onshore
Alabama
California
Colorado
Kansas
Louisiana
Michigan
Mississippi
Montana
New Mexico
North Dakota
Oklahoma
Texas
Utah
Wyoming
Total United States Onshore
United States Offshore (Federal Waters)
Alabama
California
Louisiana
Mississippi
Texas
Total United States Offshore (Federal Waters)
International
Argentina
China
Denmark
Ecuador
Equatorial Guinea
Israel
Netherlands
United Kingdom
Vietnam
Total International
Total
Developed Acreage (1)(2) Undeveloped Acreage (2)(3)(4)
Net Acres
Gross Acres
Gross Acres
Net Acres
4,902
67,339
93,918
52,151
878
196,028
2,117
678
144,373
86,073
5,160
31,545
685,162
103,680
38,834
591,963
28,171
220,085
982,733
28,988
7,413
12,355
45,203
123,552
865
80,810
299,186
2,048
58,945
52,833
9,162
34
116,677
826
339
52,972
40,144
2,433
18,831
355,244
43,430
12,039
251,317
15,809
100,490
423,085
3,977
4,225
12,355
15,727
58,142
130
4,646
99,202
2,657
5,002
28,705
17,803
38,023
1,876
1,884
5,488
2,520
4,082
19,191
196,038
4,956
70,590
398,815
41,661
52,364
407,705
119,024
143,928
764,682
2,398,970
2,569,522
81,050
851,771
266,754
1,028,796
74,749
521,230
1,701,812
9,494,654
506
3,832
18,342
11,907
10,002
427
51
2,224
1,873
3,087
7,207
61,008
4,254
47,272
171,992
25,123
9,422
288,823
55,199
92,094
470,661
2,326,204
1,328,314
32,420
851,771
92,808
338,538
11,212
153,807
1,309,034
6,444,108
1,967,081
877,531
10,658,151
7,086,761
(1) Developed acreage is acreage spaced or assignable to productive wells.
(2) 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.
(3) 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. Included within undeveloped acreage are those leased
acres (held by production under the terms of a lease) that are not within the spacing unit containing, or acreage
assigned to, the productive well so holding such lease.
(4) The Argentina acreage includes two concessions totaling 2,314,633 acres subject to final regulatory approval.
15
Item 3.
Legal Proceedings.
(a) The Company and its subsidiaries are involved in various legal proceedings in the ordinary course of
business. These proceedings are subject to the inherent uncertainties in any litigation. The Company is
defending itself vigorously in all such matters and does not believe that the ultimate disposition of such
proceedings will have a material adverse effect on the Company’s consolidated financial position, results of
operations or liquidity.
(b) On October 15, 2002, Noble Gas Marketing, Inc., Samedan Oil Corporation and Aspect Resources L.L.C.,
collectively referred to as the “Noble Defendants,” filed proofs of claim in the United States Bankruptcy
Court for the Southern District of New York in response to bankruptcy filings by Enron Corporation and
certain of its subsidiaries and affiliates, including Enron North America Corporation (“ENA”), under
Chapter 11 of the U.S. Bankruptcy Code. The proofs of claim relate to certain natural gas sales agreements
and aggregate approximately $18 million.
On December 13, 2002, ENA filed a complaint in which it objected to the Noble Defendants’ proofs of claim,
sought recovery of approximately $60 million from the Noble Defendants under the natural gas sales
agreements, sought declaratory relief in respect of the offset rights of the Noble Defendants and sought to
invalidate the arbitration provisions contained in certain of the agreements in issue. The Noble Defendants
intend to vigorously defend against ENA’s claims and do not believe that the ultimate disposition of the
bankruptcy proceeding will have a material adverse effect on the Company’s consolidated financial position,
results of operations or liquidity.
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 2002.
16
Executive Officers of the Registrant
The following table sets forth certain information, as of March 11, 2003, with respect to the executive officers of the
Registrant.
Name
Charles D. Davidson (1)
Alan R. Bullington (2)
Robert K. Burleson (3)
Age
53
51
45
Position
Chairman of the Board, President, Chief Executive Officer and Director
Vice President, International
Vice President, Business Administration and President, Noble Energy
Marketing, Inc.
Susan M. Cunningham (4)
47
Senior Vice President, Exploration
Albert D. Hoppe (5)
James L. McElvany (6)
58
49
Senior Vice President, General Counsel and Secretary
Senior Vice President, Chief Financial Officer and Treasurer
Richard A. Peneguy, Jr. (7)
52
Vice President, Offshore
William A. Poillion, Jr. (8)
53
Senior Vice President, Production and Drilling
Ted A. Price (9)
David L. Stover (10)
Kenneth P. Wiley (11)
43
45
50
Vice President, Onshore
Vice President, Business Development
Vice President, Information Systems
(1) Charles D. Davidson has served as President and Chief Executive Officer of the Company since October 2000
and Chairman of the Board since April 2001. Prior to October 2000, he served as President and Chief
Executive Officer of Vastar Resources, Inc. (“Vastar”) 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 December 1992 to October 1993, he was
Senior Vice President of the Eastern District for ARCO Oil and Gas Company. From 1988 to December 1992,
he held various positions with ARCO Alaska, Inc. Mr. Davidson, age 53, joined ARCO in 1972.
(2) Alan R. Bullington was appointed Vice President and General Manager, International Division of Samedan
Oil Corporation on January 1, 1998 and on April 24, 2001 was elected a Vice President of the Company. 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.
(3) Robert K. Burleson was elected a Vice President of the Company on April 24, 2001 and has been in charge of
the Company’s Business Administration Department since April 2002. He has also served as President of
Noble Gas Marketing, Inc. (now Noble Energy Marketing, Inc.) since June 14, 1995. Prior thereto, he served
as Vice President-Marketing for Noble Gas Marketing since its inception in 1994. Previous to his employment
17
with the Company, he was employed by Reliant Energy as Director of Business Development for its interstate
pipeline, Reliant Gas Transmission.
(4) Susan M. Cunningham has served as the Company’s Senior Vice President of Exploration since April 2001. In
this role, she oversees the Company’s worldwide exploration activities. Prior to joining the Company, 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, being appointed a Vice President in 1998 and responsible, in 1999, for Statoil’s West Africa
exploration efforts.
(5) Albert D. Hoppe has served as Senior Vice President, General Counsel and Secretary of the Company since
December 2000. Prior thereto, he served as Vice President, General Counsel and Secretary of Vastar
Resources, Inc. from 1994 through 2000. Prior to his Vastar service, he held various executive and
management legal positions with Atlantic Richfield Company.
(6) James L. McElvany has served as Senior Vice President, Chief Financial Officer and Treasurer of the
Company since July 2002. Prior thereto, he served as Vice President-Finance, Treasurer and Assistant
Secretary since July 1999. Prior to July 1999, he had served as Vice President-Controller of the Company
since December 1997. Prior thereto, he served as Controller of the Company since December 1983.
(7) Richard A. Peneguy, Jr. was elected a Vice President of the Company on April 24, 2001 and has served as Vice
President and General Manager, Offshore Division of Samedan Oil Corporation since February 2002. Prior
thereto, he served as Vice President and General Manager, Onshore Division of Samedan since January 2000.
Prior thereto, he served as General Manager, Onshore Division of Samedan since January 1, 1991.
(8) William A. Poillion, Jr. was elected a Senior Vice President of the Company on April 24, 2001 and has served
as Senior Vice President-Production and Drilling of Samedan Oil Corporation since January 1998. Prior
thereto, he served as Vice President-Production and Drilling of Samedan since November 1990. From
March 1, 1985 to October 31, 1990, he served as Manager of Offshore Production and Drilling for Samedan.
(9) Ted A. Price was appointed a Vice President of the Company and Division Manager for the Onshore Division
on January 29, 2002. Previously, he served as Manager of Onshore Exploration since 1999. Mr. Price joined
the Company in 1981 as a geologist.
(10) David L. Stover was elected the Company’s Vice President of Business Development on December 16, 2002.
Previous to his employment with the Company, he was employed by BP as Vice President, Gulf of Mexico
Shelf from September 2000 to August 2002. Prior to joining BP, Mr. Stover was employed by Vastar
Resources, Inc. 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.
(11) Kenneth P. Wiley has served as the Company’s Vice President-Information Systems since July 1998. Prior
thereto, he served as Manager-Information Systems for Samedan Oil Corporation since November 1994.
Officers serve until the next annual organizational meeting of the Board of Directors or until their successors are
chosen and qualified. No officer or executive officer of the Registrant currently has an employment agreement with
the Registrant or any of its subsidiaries, although Mr. Davidson had an employment agreement with the Registrant
until February 1, 2002. There are no family relationships among any of the Registrant’s officers.
18
PART II
Item 5.
Market for Registrant’s Common Equity and Related Stockholder Matters.
Common Stock. The Registrant’s Common Stock, $3.33 1/3 par value (“Common Stock”), is listed and traded on the
New York Stock Exchange under the symbol “NBL.” The declaration and payment of dividends are at the discretion
of the Board of Directors of the Registrant and the amount thereof will depend on the Registrant’s 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 following table sets forth, for the periods indicated, the high and low
sales price per share of Common Stock on the New York Stock Exchange and quarterly dividends paid per share.
2002
First quarter
Second quarter
Third quarter
Fourth quarter
2001
First quarter
Second quarter
Third quarter
Fourth quarter
High
$40.00
$40.76
$36.34
$40.50
$51.09
$45.20
$38.19
$40.00
Low
$30.76
$34.70
$26.65
$31.55
$39.63
$34.26
$27.50
$30.00
Dividends
Per Share
$.04
$.04
$.04
$.04
$.04
$.04
$.04
$.04
Transfer Agent and Registrar. The transfer agent and registrar for the Common Stock is Wachovia Bank, N.A.,
NC1153, 1525 West W. T. Harris Blvd., 3C3, Charlotte, North Carolina 28262-1153.
Stockholders’ Profile. As of December 31, 2002, the number of holders of record of Common Stock was 1,085. The
following chart indicates the common stockholders by category.
December 31, 2002
Individuals
Joint accounts
Fiduciaries
Institutions
Nominees
Foreign
Total-Excluding Treasury Shares
Shares
Outstanding
602,640
55,350
221,479
2,551,728
53,922,073
9,275
57,362,545
Sales of Unregistered Securities. Prior to January 2002, AMCCO was a 50 percent owned joint venture that owned an
indirect 90 percent interest in AMPCO, which completed construction of a methanol plant in Equatorial Guinea in the
second quarter of 2001. During 1999, AMCCO issued $125 million Series A-1 and $125 million Series A-2 senior
secured notes due December 15, 2004 to fund the remaining construction payments. On January 2, 2002, the
Company’s partner in AMCCO directed AMCCO to sell 50 percent of its interest in AMPCO as a component of the
partner’s sale of its Equatorial Guinea assets. The proceeds of the AMPCO sale were used to repay in full AMCCO’s
$125 million Series A-1 Notes on January 28, 2002 and to make a distribution to the Company’s partner. Since the
Company’s partner in AMCCO no longer retains an economic interest in AMPCO, the Company began consolidating
19
AMCCO’s debt in 2002, thereby including the $125 million Series A-2 Notes in the Company’s balance sheet
effective January 28, 2002. The terms of the $125 million Series A-2 Notes remain unchanged. The plant construction
started during 1998 and initial production of commercial grade methanol commenced May 2, 2001. At the same time
the Series A-2 Notes were issued, the Company guaranteed the payment of interest on the Series A-2 Notes and
issued, in a private placement pursuant to Section 4(2) of the Securities Act, 125,000 shares of its Series B
Mandatorily Convertible Preferred Stock (the “Series B Preferred”), par value $1.00 per share to Noble Share Trust,
which is a Delaware statutory business trust, in exchange for all of the beneficial ownership interests in the Noble
Share Trust.
Noble Share Trust holds the 125,000 shares of Series B Preferred for the benefit of the holders of the Series A-2
Notes. The Series A-2 indenture trustee, and the holders of 25 percent of the outstanding principal amount of the
Series A-2 Notes, would have the right to require a public offering of the Series B Preferred to generate proceeds
sufficient to repay the Series A-2 Notes, upon the occurrence of certain events (“Trigger Dates”), including (i) defaults
under the Indenture governing the Series A-2 Notes, (ii) a default and acceleration of the Company’s debt exceeding
five percent of the Company’s consolidated net tangible assets, and (iii) the simultaneous occurrence of a downgrade
of the Company’s unsecured senior debt rating to “Ba1” or below by Moody’s or “BB+” or below by Standard &
Poor’s and a decline in the closing price of the Company’s common stock for three consecutive trading days to below
$17.50. The exercise of this mandatory remarketing right is subject to certain forbearance provisions that would allow
the Company the opportunity to obtain funds for the repayment of the Series A-2 Notes by alternative means for a
specified period of time.
The terms of the Series B Preferred, including dividend and conversion features, would be reset at the time of the
remarketing, based on the recommendation of Credit Suisse First Boston, as Remarketing Agent, as to the terms
necessary to generate proceeds to repay the Series A-2 Notes. If the Remarketing Agent is not able to complete a
registered public offering of the Series B Preferred, it may under certain circumstances conduct a private placement of
such stock. If it were impossible for legal reasons to remarket the Series B Preferred, the Company would be obligated
to repay the Series A-2 Notes.
The Series B Preferred stock would be mandatorily convertible into the Company’s common stock three years after
remarketing (or failed remarketing). Generally, each share of Series B Preferred would then be mandatorily
convertible at the “Mandatory Conversion Rate,” which is equal to the following number of shares of the Company’s
common stock:
(a) if the Mandatory Conversion Date Market Price is greater than or equal to the Threshold Appreciation
Price, the quotient of (i) $1,000 divided by (ii) the Threshold Appreciation Price;
(b) if the Mandatory Conversion Date Market Price is less than the Threshold Appreciation Price but is
greater than the Reset Price, the quotient of $1,000 divided by the Mandatory Conversion Date Market Price;
and
(c) if the Mandatory Conversion Date Market Price is less than or equal to the Reset Price, the quotient of
$1,000 divided by the Reset Price.
“Mandatory Conversion Date Market Price” means the average closing price per share of the Company’s common
stock for the 20 consecutive trading days immediately prior to, but not including, the mandatory conversion date.
“Threshold Appreciation Price” means the product of (i) the Reset Price (as the same may be adjusted from time to
time) and (ii) 110 percent.
“Reset Price” means the higher of (i) the closing price of a share of the Company’s common stock on the Trigger Date
or (ii) the quotient (rounded up to the nearest cent) of $125,000,000 divided by the number, as of the Trigger Date, of
20
the authorized but unissued shares of common stock that have not been reserved as of the Trigger Date by the
Company’s Board of Directors for other purposes.
In addition to the mandatory conversion discussed above, each share of the Series B Preferred is generally convertible,
at the option of the holder thereof at any time before the mandatory conversion date, into 36.364 shares of the
Company’s common stock (the “Optional Conversion Rate”); provided, however, that the Optional Conversion Rate
shall adjust, as of the earlier to occur of remarketing or failed remarketing, to the quotient of (i) $1,000 divided by (ii)
the Threshold Appreciation Price.
21
Item 6.
Selected Financial Data.
(in thousands, except per share amounts and ratios) 2002
Revenues and Income
Year Ended December 31,
2001
2000
1999
1998
Revenues
Net cash provided by operating activities
Net income (loss)
Per Share Data
$ 1,443,728 $ 1,588,690 $ 1,399,457 $ 918,349 $ 906,787
382,010
570,334
(164,025)
191,597
635,772
133,575
343,100
49,461
504,291
17,652
Basic earnings (loss) per share
Cash dividends
Year-end stock price
Basic weighted average shares outstanding
$
$
$
.31 $
.16 $
37.55 $
57,196
2.36 $
.16 $
35.29 $
56,549
3.42 $
$
.16
$
46.00
55,999
.87 $
.16 $
21.44 $
57,005
(2.88)
.16
24.63
56,955
Financial Position (at year end)
Property, plant and equipment, net:
Oil and gas mineral interests,
equipment and facilities
Total assets
Long-term obligations:
Long-term debt, net of current portion
Deferred income taxes
Other
Shareholders’ equity
Ratio of debt-to-book capital
Capital Expenditures
Oil and gas mineral interests,
equipment and facilities
Methanol and power projects
Other
Total capital expenditures
$ 2,139,785 $ 1,953,211 $ 1,485,123
1,879,280
2,479,848
2,730,015
$ 1,242,370 $ 1,429,667
1,686,080
1,420,351
977,116
201,939
69,820
1,009,386
.50
837,177
176,259
75,629
1,010,198
.47
525,494
117,048
61,639
849,682
.38
445,319
83,075
53,877
683,609
.39
745,143
106,823
52,868
642,080
.54
$ 543,967 $ 765,291 $ 502,430
98,737
4,430
$ 604,798 $ 862,939 $ 605,597
57,646
3,185
95,716
1,932
$ 121,077 $ 445,910
25,131
2,733
$ 212,215 $ 473,774
89,728
1,410
For additional information, see “Item 8. Financial Statements and Supplementary Data” of this Form 10-K.
Operating Statistics
Natural Gas
Sales (in millions)
Production (MMcfpd)
Average realized price (per Mcf)
Crude Oil
Sales (in millions)
Production (Bopd)
Average realized price (per Bbl)
2002
$ 392.1
387.6
$ 2.92
Year Ended December 31,
2001
2000
1999
1998
$ 595.4
422.4
$ 3.98
$ 553.7
406.3
$ 3.80
$ 365.1
455.1
$ 2.26
$ 446.0
566.6
$ 2.20
$ 292.9
34,037
$ 23.98
$ 255.5
30,661
$ 23.30
$ 229.6
25,805
$ 24.95
$ 180.6
30,003
$ 16.81
$ 160.6
37,217
$ 12.12
Royalty sales (in millions)
$ 15.6
$ 20.9
$ 17.3
$ 14.0
$ 13.1
22
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
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 7a. Quantitative and Qualitative Disclosures About Market Risk - Cautionary Statement for Purposes of the
Private Securities Litigation Reform Act of 1995 and Other Federal Securities Laws” of this Form 10-K.
CRITICAL ACCOUNTING POLICIES AND PRACTICES
The preparation of the consolidated financial statements requires management of the Company 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. The Company’s estimates of crude oil and natural gas reserves are the most significant.
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 natural gas and crude oil 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.
The Company accounts for its 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 developed crude oil and natural gas reserves on a property-by-property basis as estimated by Company
engineers. Through December 31, 2002, estimated future restoration and abandonment costs are recorded by charges
to depreciation, depletion and amortization (“DD&A”) expense over the productive lives of the related properties.
The Company generally recognizes revenue when the product is delivered to a third-party purchaser. The Company
follows the entitlements method of accounting for its natural gas imbalances. Natural gas imbalances occur when the
Company sells more or less natural gas than it is entitled to under its ownership percentage of total natural gas
production. Any excess amount received above the Company’s share is treated as a liability. If less than the
Company’s entitlement is received, the underproduction is recorded as a receivable.
The Company, directly or through its subsidiaries, from time to time, uses various derivative arrangements in
connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such
arrangements include fixed price hedges, costless collars and other contractual arrangements. The Company accounts
for its derivative arrangements under Statement of Financial Accounting Standard (“SFAS”) No. 133, “Accounting for
Derivative Instruments and Hedging Activities,” and has elected to designate its derivative arrangements as cash flow
hedges.
Other significant items subject to estimates and assumptions include the carrying amount of property, plant and
equipment; valuation allowances for receivables, inventories and deferred income tax assets; environmental liabilities;
valuation of derivative instruments; and assets and obligations related to employee benefits. Actual results could differ
from those estimates. Management believes it is necessary to understand the Company’s significant accounting
policies, “Item 8. Financial Statements and Supplementary Data--Note 1 - Summary of Significant Accounting
Policies” of this Form 10-K, in order to understand the Company’s financial condition, changes in financial condition
and results of operations.
23
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
The Company’s net cash provided from operations in 2002 was lower than 2001 due to lower natural gas prices and
decreased gas production volumes, offset partially by higher oil prices and increased oil production volumes. Net cash
from operating activities per BOE of production and per share are shown in the charts below.
E
O
B
/
$
20
10
0
$17.23
$16.68
$14.00
$11.24
$10.18
$8.81
e
r
a
h
S
/
$
15
10
5
0
2002
2001
2000
2002
2001
2000
The crude oil price received by the Company in 2002 increased three percent from 2001 and the natural gas price
received by the Company decreased 27 percent in 2002 from the price received in 2001. In 2001, the Company’s
crude oil price decreased nine percent and the natural gas price increased five percent compared to 2000.
Prior to January 2002, AMCCO was a 50 percent owned joint venture that owned an indirect 90 percent interest in
AMPCO, which completed construction of a methanol plant in Equatorial Guinea in the second quarter of 2001.
During 1999, AMCCO issued $125 million Series A-1 and $125 million Series A-2 senior secured notes due
December 15, 2004 to fund the remaining construction payments. On January 2, 2002, the Company’s partner in
AMCCO directed AMCCO to sell 50 percent of its interest in AMPCO as a component of the partner’s sale of its
Equatorial Guinea assets. The proceeds of the AMPCO sale were used to repay in full AMCCO’s $125 million Series
A-1 Notes on January 28, 2002 and to make a distribution to the Company’s partner. Since the Company’s partner in
AMCCO no longer retains an economic interest in AMPCO, the Company began consolidating AMCCO’s debt in
2002, thereby including the $125 million Series A-2 Notes in the Company’s balance sheet effective January 28, 2002.
The terms of the $125 million Series A-2 Notes remain unchanged. The plant construction started during 1998 and
initial production of commercial grade methanol commenced May 2, 2001. The total costs of the plant and supporting
facilities as of December 31, 2002 were $417 million, with the Company responsible for $208.5 million. During 2002,
the Company recorded costs of $7 million toward the project.
During 2002, $544 million was spent on acquisition, exploration and development projects, $7 million on the
methanol project, $51 million on the Machala power project in Ecuador and $3 million for various other projects for
total expenditures of $605 million. The 2003 capital expenditures budget is approximately $510 million.
The Company’s current ratio (current assets divided by current liabilities) was .66:1 at December 31, 2002, compared
with .92:1 at December 31, 2001. The decrease in the current ratio was due to a $57.8 million decrease in cash and
short-term investments coupled with an $81.8 million increase in accounts payable.
24
Financing
The Company’s total long-term debt, net of unamortized discount, at December 31, 2002, was $977 million compared
to $837 million at December 31, 2001. If the $125 million AMCCO debt had been included, the total long-term debt
would have been $962 million at December 31, 2001. The ratio of debt-to-book capital (defined as the Company’s
total debt plus its equity) was 50 percent at December 31, 2002, compared with 47 percent at December 31, 2001.
(in thousands)
Contractual
Obligations
Long-term debt
Drilling obligations
Total contractual cash obligations
Payments Due by Period
Total
$ 1,025,246
118,211
$ 1,143,457
$
Less Than
1 Year
41,919
116,411
$ 158,330
1 to 3
Years
$ 153,327
1,800
$ 155,127
4 to 5
Years
$ 380,000
After 5
Years
$ 450,000
$ 380,000
$ 450,000
The Company’s long-term debt, net of current portion, is comprised of:
•
•
•
•
•
•
•
•
$250 million of 8% Senior Notes Due 2027
$100 million of 7 1/4% Notes Due 2097
$100 million of 7 1/4% Notes Due 2023
$380 million on the $400 million credit facility based upon a Eurodollar rate plus a range of 60 to 145 basis
points depending upon the percentage of utilization and credit rating, maturing in 2006. The interest rate at
December 31, 2002 was 2.47 percent. The interest rate at December 31, 2001 was 3.0 percent.
$125 million of 8.95% Series A-2 Notes on the AMCCO debt, payable in 2004. There was no AMCCO debt
on the Company’s balance sheet at December 31, 2001.
$20.4 million on the Israel debt based upon the London Interbank Offering Rate (“LIBOR”) plus 75 basis
points, payable in 2004. The interest rate at December 31, 2002 was 2.18 percent. There was no outstanding
Israel debt at December 31, 2001.
$7.9 million of the 6.25% Aspect acquisition note, payable in 2004
($6.2) million unamortized discount
The Company entered into a new $400 million five-year credit agreement on November 30, 2001 with certain
commercial lending institutions which exposes the Company to the risk of earnings or cash flow loss due to changes
in market interest rates. The interest rate is based upon a Eurodollar rate plus a range of 60 to 145 basis points
depending upon the percentage of utilization and credit rating. At December 31, 2002, there was $380 million
borrowed against this credit agreement, which has a maturity date of November 30, 2006. For more information, see
“Item 8. Financial Statements and Supplementary Data--Note 3 - Debt” of this Form 10-K.
The Company also entered into a new $200 million 364-day credit agreement on November 27, 2002 with certain
commercial lending institutions which exposes the Company to the risk of earnings or cash flow loss due to changes
in market interest rates. The interest rate is based upon a Eurodollar rate plus a range of 62.5 to 150 basis points
depending upon the percentage of utilization and credit rating. At December 31, 2002, there were no amounts
outstanding under this credit agreement. The agreement has a maturity date of November 26, 2003 for the revolving
commitment and a maturity date of November 25, 2004 for the term commitment that includes any balance remaining
after the revolving commitment matures. For more information, see “Item 8. Financial Statements and Supplementary
Data--Note 3 - Debt” of this Form 10-K.
Financial covenants on both the $400 million and $200 million credit facilities include the following: (a) the ratio of
Earnings Before Interest, Taxes, Depreciation and Exploration Expense (“EBITDAX”) to total interest expense for
any consecutive period of four fiscal quarters ending on the last day of a fiscal quarter may not be less than 4.0 to 1.0;
(b) the total debt to capitalization ratio, expressed as a percentage, may not exceed 60 percent at any time; and (c) the
total asset value of the Company’s restricted subsidiaries may not be less than $800 million at any time.
25
The Company had no short-term borrowings outstanding on December 31, 2002. The Company had a $25 million
short-term note payable outstanding December 31, 2001, which was repaid January 28, 2002. The note was an
uncommitted facility with an interest rate of 3.25 percent for the period December 28, 2001 to January 28, 2002.
On January 2, 2002, the Company’s partner in AMCCO directed AMCCO to sell 50 percent of its interest in AMPCO
as a component of the partner’s sale of its Equatorial Guinea assets. The proceeds of the AMPCO sale were used to
repay in full AMCCO’s $125 million Series A-1 Notes on January 28, 2002 and to make a distribution to the
Company’s partner. Since the Company’s partner in AMCCO no longer retains an economic interest in AMPCO, the
Company began consolidating AMCCO’s debt in 2002, thereby including the $125 million Series A-2 Notes in the
Company’s balance sheet effective January 28, 2002. The terms of the $125 million Series A-2 Notes remain
unchanged.
Other
The Company has paid quarterly cash dividends of $.04 per share since 1989 and currently anticipates it will continue
to pay quarterly dividends of $.04 per share.
The Company’s Board of Directors, in February 2000, authorized a repurchase of up to $50 million in the Company’s
common stock. In the first quarter of 2000, the Company repurchased approximately $30 million of common stock.
The 2000 repurchase of 1,386,400 shares at an average cost of $21.84 per share was funded from the Company’s
current cash flow. On September 17, 2001 the Company’s Board of Directors approved an expansion of the original
repurchase program from $50 million to $100 million. During the fourth quarter of 2001, in conjunction with the
expanded repurchase program, the Board approved a stock repurchase forward program. Under the stock repurchase
forward program, one of the Company’s banks purchased approximately $35 million of the Company’s stock or
1,044,454 shares on the open market during the first quarter of 2002.
The program was scheduled to mature in January 2003 but has been extended to January 2004. Under the provisions
of the agreement with the bank, the Company can choose to either purchase the shares from the bank, issue additional
shares to the bank to the extent that the share price has decreased, pay the bank a net amount of cash to the extent that
the share price has decreased, or receive from the bank a net amount of cash to the extent that the share price has
increased. The bank has the right to terminate the agreement prior to the maturity date if the Company’s share price
decreases by 50 percent (to $16.77 per share) or if the Company’s credit rating is downgraded below BBB- (S&P) or
Baa3 (Moody’s). If either event occurs and the bank exercises its right to terminate, the Company still retains the right
to settle in cash or additional shares. The agreement limits the number of shares to be issued by the Company to
14,000,000 additional shares. Amounts paid or received related to the change in share price will be an addition or
reduction to the Company’s capital in excess of par value. No settlements have occurred to date. As of
December 31, 2002, the fair value of the Company’s obligation under the contract would be an obligation to pay
approximately $36.1 million to the bank (and hold the shares as treasury stock), or the bank would return 81,946
shares of Company stock to the Company, or the bank would pay $3.1 million to the Company.
The Company has sold a number of non-strategic crude oil and natural gas properties over the past three years. Total
amounts of crude oil and natural gas reserves associated with the 2002 and 2000 dispositions were .7 MMBbls of oil
and 20.3 Bcf of gas and 1.2 MMBbls of oil and 4.8 Bcf of gas, respectively. There were no significant sales of oil or
gas properties in 2001. The Company believes the disposition of non-strategic properties furthers the goal of
concentrating its efforts on strategic properties.
During 2002, the Company paid $7 million related to certain operating contingencies that had previously been
accrued.
26
The Financial Accounting Standards Board (“FASB”) issued SFAS No. 133, “Accounting for Derivative Instruments
and Hedging Activities,” in June 1998. The Statement established accounting and reporting standards requiring every
derivative instrument (including certain derivative instruments embedded in other contracts) to be recorded in the
balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the
derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met wherein
gains and losses are reflected in shareholders’ equity as other comprehensive income until the hedged item is
recognized. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on
the hedged item in the statement of operations, and requires that a company formally document, designate and assess
the effectiveness of transactions that receive hedge accounting. The Company adopted SFAS No. 133 effective
January 1, 2001. The adoption of this statement did not have a material impact on the Company’s results of operations
or financial position.
RESULTS OF OPERATIONS
Net Income and Revenues
The Company’s net income for 2002 was $17.7 million, a decrease of $115.9 million from 2001. The decrease was
due primarily to a $208.3 million decrease in natural gas sales, offset by a $37.1 million increase in crude oil sales.
The decrease in net income for 2001 compared to 2000 was due to a $61.2 million increase in dry hole expense, offset
by a $3.8 million decrease in abandoned asset expense.
Natural Gas Information
Natural gas revenues decreased 34 percent in 2002 due to a 27 percent decrease in the average natural gas price
coupled with an eight percent decrease in natural gas production. In the United States, natural gas production
decreased 13 percent due to reduced drilling activity, natural decline rates for properties in the Gulf of Mexico and the
onshore Gulf Coast region, as well as temporary shut-ins related to Hurricanes Isidore and Lili, coupled with a 25
percent decrease in the average natural gas price. In the North Sea, natural gas revenues decreased 15 percent due to
an 11 percent decrease in the average natural gas price coupled with a five percent decrease in natural gas production.
In Equatorial Guinea, natural gas revenues increased 39 percent due to the full year of operations of the methanol
plant.
Natural gas revenues for 2001 increased eight percent due to a four percent increase in natural gas production coupled
with a five percent increase in the average natural gas price compared to 2000. The methanol plant in Equatorial
Guinea began operations on May 2, 2001, which accounted for the increased natural gas production compared to
2000.
The table below depicts average daily natural gas production in Mcf by area for the last three years.
United States
North Sea
Equatorial Guinea
Other International
Total
2002
327,451
16,991
34,382
8,799
387,623
2001
378,475
17,830
24,488
1,651
422,444
2000
378,101
23,676
2,572
1,970
406,319
Natural gas production during 2002 ranged from a low of 351.8 MMcfpd in May, to a high of 424.3 MMcfpd in
January. Natural gas accounted for 57 percent of the Company’s total natural gas and crude oil revenues in 2002.
27
2002 Daily Production by Quarter
Natural Gas
Crude Oil
408.6
374.4
383.2
384.6
f
c
M
M
500
400
300
200
100
0
s
l
b
B
M
40
30
20
10
0
34.4
34.6
34.3
32.8
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Crude Oil Information
Crude oil revenues increased 14 percent during 2002 due to an 11 percent increase in production coupled with a three
percent increase in the average crude oil price. In the North Sea, crude oil revenues increased 80 percent due to a full
year of production from the Hanze field, the commencement of production from the Hannay field in March 2002 and
an eight percent increase in the average crude oil price. In Equatorial Guinea, crude oil revenues increased 18 percent
due to a 14 percent increase in production from the Alba field, coupled with a four percent increase in the average
crude oil price.
Crude oil revenues increased 11 percent in 2001, compared to 2000, due to a 19 percent increase in production offset
by a seven percent decline in the average price received for 2001. In the North Sea, crude oil revenues increased 136
percent due to the commencement of production from the Hanze field in August 2001, offset by a 10 percent decrease
in the average crude oil price. In Equatorial Guinea, crude oil revenues increased 52 percent due to an 85 percent
increase in production from the Alba field, offset by a 17 percent decline in the average price.
The table below depicts average daily crude oil production in Bbls by area for the last three years.
United States
North Sea
Equatorial Guinea
Other International
Total
2002
18,110
7,847
5,259
2,821
34,037
2001
18,614
4,688
4,620
2,739
30,661
2000
19,019
1,787
2,497
2,502
25,805
Crude oil production during 2002 ranged from a low of 31,060 Bopd in July, to a high of 36,381 Bopd in April. Crude
oil accounted for 43 percent of the Company’s total natural gas and crude oil revenues in 2002.
Derivatives and Hedging Activities
The Company, directly or through its subsidiaries, from time to time, uses various hedging arrangements in connection
with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such
arrangements include fixed price hedges, costless collars and other contractual arrangements. Although these hedging
arrangements expose the Company to credit risk, the Company monitors the creditworthiness of its counterparties and
believes that losses from nonperformance are unlikely to occur. Hedging gains and losses related to the Company’s
28
crude oil and natural gas production are recorded in crude oil and natural gas sales and royalties. For more
information, see “Item 7a. Quantitative and Qualitative Disclosures About Market Risk” of this Form 10-K.
Costs and Expenses
Crude oil and natural gas operations expense, consisting of lease operating expense, workover expenses, production
taxes and other related lifting costs, was flat overall, in absolute dollars, in 2002 compared to 2001. In the North Sea,
operations expense increased 78 percent due to a full year of production operations from the Hanze field and the
commencement of operations from the Hannay field in March 2002. In Equatorial Guinea, operations expense
increased 45 percent due to the increased production from the Alba field. Domestic operations expense decreased in
absolute terms during 2002 offsetting the international increases. Crude oil and natural gas operations expense
increased 10 percent overall in 2001 from 2000. In the North Sea, operations expense increased 16 percent due to the
commencement of operations of the Hanze field in August 2001. In Equatorial Guinea, operations expense increased
61 percent due to the commencement of natural gas deliveries to the methanol plant in May 2001. Included in
operations expense were workover costs of $8.5 million, $15.1 million and $21.1 million for 2002, 2001 and 2000,
respectively. The workovers increased operations expense in such periods by $.04, $.07 and $.10 per Mcfe,
respectively.
Operating Expenses
Workovers
$133.8
$133.5
$121.9
$8.5
$15.1
$21.1
2002
2001
2000
DD&A Expenses
$285
$284
$231
2002
2001
2000
M
M
$
300
250
200
150
100
50
0
M
M
$
150
120
90
60
30
0
In 2002, DD&A expense increased slightly compared to 2001. In the North Sea, DD&A expense increased 71 percent
due to a full year’s production of the Hanze field. In Equatorial Guinea, DD&A expense increased 50 percent due to
the results of the field expansion, which included a full year of natural gas sales to the methanol plant. The unit rate of
DD&A per BOE was $7.92 in 2002.
In 2001, DD&A expense increased 23 percent overall compared to 2000. In the United States, DD&A expense
increased 22 percent due to increased development costs incurred in the Gulf of Mexico to stabilize production
volumes. In the North Sea, DD&A expense increased 34 percent due to the commencement of production from the
Hanze field in August 2001. In Equatorial Guinea, DD&A expense increased 186 percent due to the commencement
of natural gas sales to the methanol plant in May 2001. The unit rate of DD&A per BOE was $7.70 in 2001.
Through December 31, 2002, the Company provided for the cost of future liabilities related to restoration and
dismantlement costs for offshore facilities. This provision is based on the Company’s best estimate of such costs to be
incurred in future years based on information from the Company’s engineers. These estimated costs were provided
through charging DD&A expense using a ratio of production divided by reserves multiplied by the estimated costs to
dismantle and restore. The Company adopted SFAS No. 143 on January 1, 2003 and will recognize, as the fair value
of asset retirement obligations, $99.7 million related to the United States and $10.0 million related to the North Sea.
The Company’s accumulated provision for future dismantlement and restoration cost was $84.1 million at
29
December 31, 2002, $80.0 million at December 31, 2001 and $79.7 million at December 31, 2000. The Company has
not determined the cumulative effect of adoption of this standard. Total estimated future dismantlement and restoration
costs of $206.6 million, which consists of $188.7 million for the United States and $17.9 million for the North Sea,
are included in future production and development costs for purposes of estimating the future net revenues relating to
the Company’s proved reserves. For more information, see “Item 8. Financial Statements and Supplementary Data--
Note 1 - Summary of Significant Accounting Policies” of this Form 10-K.
Crude oil and natural gas exploration expense consists of dry hole expense, unproved lease amortization, seismic and
other miscellaneous exploration expense, including lease rentals and exploration staff. The table below depicts the
exploration expense by area for the last three years.
(in thousands)
United States
Dry hole expense
Unproved lease amortization
Seismic
Other
United States Total Exploration Expense
North Sea
Dry hole expense
Unproved lease amortization
Seismic
Other
North Sea Total Exploration Expense
Other International including Israel and Equatorial Guinea
Dry hole expense
Unproved lease amortization
Seismic
Other
Other International Total Exploration Expense
Total Exploration Expense
Impairment of Operating Assets
2002
2001
2000
$ 64,449
19,426
14,282
22,538
$ 120,695
$
$
544
178
827
3,661
5,210
$ 16,403
1,650
5,383
1,360
$ 24,796
$ 150,701
$ 54,810
15,112
13,328
17,242
$ 100,492
$ 28,992
1,725
2,209
2,024
$ 34,950
$ 15,882
376
70
326
$ 16,654
$ 152,096
$ 37,281
15,675
17,794
9,617
$ 80,367
$
17
239
1,140
1,396
$
$
1,165
400
705
835
3,105
$
$ 84,868
Developed crude oil and natural gas properties and other long-lived assets are assessed whenever events or
circumstances indicate that the carrying amount of an asset may not be recoverable. The Company performs this
review of recoverability by estimating future cash flows. If the sum of the expected future cash flows is less than the
carrying amount of the asset, an impairment is recognized based on the fair value of the assets as determined using the
expected present value of future net cash flows. The Company recorded no operating asset impairments during 2002,
2001 or 2000. Individually significant unproved crude oil and natural gas properties are periodically assessed for
impairment of value and a loss is recognized at the time of impairment by providing an impairment allowance.
Selling, General and Administrative Expenses (“SG&A”)
SG&A expenses increased $3.5 million in 2002 compared to 2001 and decreased $3.1 million in 2001 compared to
2000. The increase in SG&A expenses for 2002 is due to increased salary and legal expense, as well as increased costs
associated with the Company’s international expansion. The decrease in 2001 compared to 2000 reflects the
Company’s effort to reduce SG&A through efficiencies and other reduction measures.
30
Gathering, Marketing and Processing
NEMI markets the majority of the Company’s domestic natural gas, as well as certain third-party natural gas. NEMI
sells natural gas directly to end-users, natural gas marketers, industrial users, interstate and intrastate pipelines, power
generators and local distribution companies. NEMI markets a portion of the Company’s domestic crude oil, as well as
certain third-party crude oil. The Company records all of NEMI’s sales and expenses as gathering, marketing and
processing revenues and expenses. All intercompany sales and expenses have been eliminated in the Company’s
consolidated financial statements.
The gathering, marketing and processing revenues less expenses for NEMI are reflected in the table below.
(in thousands)
(amounts include inter-
company eliminations)
Revenues
Expenses
Cost of goods sold
Transportation
General and administrative
Total Expenses
Gross Margin
2002
2001
2000
Crude
Oil
$ 88,377
61,553
20,323
802
$ 82,678
$ 5,699
Natural
Gas
$ 625,714
588,022
28,284
3,857
$ 620,163
5,551
$
Crude
Oil
$ 75,550
49,191
19,739
199
$ 69,129
$ 6,421
Natural
Gas
$ 645,400
607,170
27,779
3,176
$ 638,125
7,275
$
Crude
Oil
$ 91,204
63,005
19,455
190
$ 82,650
$ 8,554
Natural
Gas
$ 498,729
464,600
24,014
3,002
$ 491,616
7,113
$
The margins for natural gas on a per MMBTU basis were $.035 for 2002 and 2001 and $.027 for 2000. The increase
in natural gas margin on a per MMBTU basis for 2001 compared to 2000 was due to the improvement in natural gas
prices. The margins for crude oil on a per Bbl basis were $.84 for 2002, $.95 for 2001 and $1.28 for 2000. The
decrease in crude oil margin for 2002 compared to 2001 was due to increased general and administrative expenses
coupled with higher transportation expense. The decrease in crude oil margin for 2001 compared to 2000 was due to
lower crude oil prices.
Income Taxes
Income tax expense decreased to $25 million in 2002 from $91 million in 2001, primarily from the decrease in
income. However, the effective income tax rate increased to 59 percent in 2002 from 41 percent in 2001. During 2002,
more of the Company’s income was from international operations. Some of the countries in which the international
operations were conducted have a higher statutory income tax rate than the United States. To a lesser extent, also
impacting the effective rate in 2002 was the lower income level.
FUTURE TRENDS
The Company expects crude oil and natural gas production to increase in 2003 and 2004 compared to 2002. The
increased production in 2003 is expected primarily from the phase 2A expansion of the Alba field in Equatorial
Guinea, the startup of production from the Mari-B field, offshore Israel, production from the CDX block in China and
a full year of production in Ecuador. The increase in 2004 is expected primarily from the continued expansion of
markets in Israel and the phase 2B expansion of the LPG plant in Equatorial Guinea.
The Company recently set its 2003 capital expenditures budget at approximately $510 million. Such expenditures are
planned to be funded principally through internally generated cash flows. The Company believes that it has the capital
structure to take advantage of strategic acquisitions, as they become available, through internally generated cash flows
or available lines of credit and other borrowing opportunities.
31
SFAS No. 148, “Accounting for Stock-Based Compensation,” was issued in December 2002. This statement amends
SFAS No. 123, “Accounting for Stock-Based Compensation,” to provide for alternative methods of transition for an
entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation.
It also amends the disclosure provisions of that statement to require prominent disclosure about the effects on reported
net income of an entity’s accounting policy decisions with respect to stock-based employee compensation.
The Company currently accounts for stock-based employee compensation plans under the recognition and
measurement principles of the Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued
to Employees.” The Company has not determined if it will adopt the fair value provisions of SFAS No. 123.
In June 2002, the Emerging Issues Task Force (“EITF”) reached a consensus on certain issues contained in
Topic 02-03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts” under EITF Issue
No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” While the
Company does not engage in material energy trading activities, the EITF has expanded its definition of energy trading
activities to include the marketing activities in which the Company is engaged. As of January 1, 2003, the Company
will present its gathering, marketing and processing activities in the statement of operations for all periods on a net
rather than a gross basis. The change will significantly decrease reported marketing sales and purchases, but will have
no effect on operating income or cash flow.
Management believes that the Company is well positioned with its balanced reserves of crude oil and natural gas and
downstream projects. The uncertainty of commodity prices continues to affect the crude oil, natural gas and methanol
industries. The Company cannot predict the extent to which its revenues will be affected by inflation, government
regulation or changing prices.
Item 7a. Quantitative and Qualitative Disclosures About Market Risk.
The Company is exposed to market risk in the normal course of its business operations. Management believes that the
Company is well positioned with its 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, the Company, from time to time, has used
derivative hedging instruments and may do so in the future as a means of managing its exposure to price changes.
During 2002, the Company entered into various natural gas costless collars, natural gas costless collar combinations
and crude oil costless collar transactions related to its production. The table below depicts the various transactions for
2002.
Natural Gas
Crude Oil
Hedge MMBTUpd
Floor price range
Ceiling price range
Percent of daily production
Gain (loss) per Mcf
170,274
$2.00 - $3.50
$2.45 - $5.10
44%
$.03
Hedge Bpd
Floor price range
Ceiling price range
Percent of daily production
Gain (loss) per Bbl
5,247
$23.00 - $24.00
$29.30 - $30.10
15%
$0
32
As of December 31, 2002, the Company had entered into costless collars related to its natural gas and crude oil
production to support the Company’s investment program as follows:
Natural Gas
Crude Oil
Production
Period
1Q 2003
2Q 2003
3Q 2003
4Q 2003
MMBTU
Per Day
185,000
185,000
185,000
185,000
Price
Per MMBTU
Floor - Ceiling
$3.87 - $4.82
$3.43 - $4.57
$3.43 - $4.60
$3.43 - $4.84
Bbls
Per Day
15,000
15,000
10,000
10,000
Price
Per Bbl
Floor - Ceiling
$23.00 - $28.63
$23.00 - $28.63
$23.00 - $27.95
$23.00 - $27.95
The contracts entitle the Company (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 last scheduled NYMEX
trading day applicable for each calculation period is less than the floor price. The Company would pay the
counterparty if the settlement price for the last scheduled NYMEX trading day applicable for each calculation period
were more than the ceiling price. The amount payable by the floating price payor, if the floating price is above the
ceiling price, is the product of the notional quantity per calculation period and the excess, if any, of the floating price
over the ceiling price in respect of each calculation period. The amount payable by the fixed price payor, if the
floating price is below the floor price, is the product of the notional quantity per calculation period and the excess, if
any, of the floor price over the floating price in respect of each calculation period.
During 2001, the Company had natural gas costless collars for the fourth quarter of 2001 for 50,000 MMBTU of
natural gas per day, with a floor price of $3.25 per MMBTU and a ceiling price of $4.60 per MMBTU. The net effect
of this fourth quarter 2001 hedge was a $.02 per Mcf increase in the average natural gas price for the year 2001. Of
the 50,000 MMBTU per day of costless collars, 25,000 MMBTU per day were terminated early, at a gain. As a result,
the Company recognized an additional $.70 per MMBTU on the 25,000 MMBTU of natural gas per day in 2001.
NEMI, from time to time, employs hedging arrangements in connection with its purchases and sales of production.
While most of NEMI’s purchases are made for an index-based price, NEMI’s customers often require prices that are
either fixed or related to NYMEX. In order to establish a fixed margin and mitigate the risk of price volatility, NEMI
may convert a fixed or NYMEX sale to an index-based sales price (such as by purchasing an index-based futures
contract obligating NEMI for delivery of production). Due to the size of such transactions and certain restraints
imposed by contract and by Company guidelines, as of December 31, 2002, the Company had no material market risk
exposure from NEMI’s hedging activity.
The Company has a $400 million credit agreement that exposes the Company to the risk of earnings or cash flow loss
due to changes in market interest rates. The interest rate is based upon a Eurodollar rate plus a range of 60 to 145 basis
points depending upon the percentage of utilization and credit rating. At December 31, 2002, there was $380 million
borrowed against this credit agreement with an interest rate of 2.47 percent and a maturity date of November 30, 2006.
A ten percent change in the December 31, 2002 interest rate on this $380 million would result in a change in interest
expense of $937,080. All other significant Company long-term debt is fixed-rate and, therefore, does not expose the
Company to the risk of earnings or cash flow loss due to changes in market interest rates. For more information, see
“Item 8. Financial Statements and Supplementary Data--Note 3 - Debt” of this Form 10-K.
The Company does not enter into foreign currency derivatives. The U.S. dollar is considered the primary currency for
each of the Company’s international operations. Transactions that are completed in a foreign currency are translated
into U.S. dollars and recorded in the financial statements. Translation gains or losses were not material in any of the
periods presented and the Company does not believe it is currently exposed to any material risk of loss on this basis.
Such gains or losses are included in other income on the statement of operations. However, certain sales transactions
33
are concluded in foreign currencies and the Company, therefore, is exposed to potential risk of loss based on
fluctuation in exchange rates from time to time.
Cautionary Statement for Purposes of the Private Securities Litigation Reform Act of 1995
and Other Federal Securities Laws
General. Noble Energy is including the following discussion to generally inform its existing and potential security
holders of some of the risks and uncertainties that can affect the Company and to take advantage of the “safe harbor”
protection for forward-looking statements afforded under federal securities laws. From time to time, the Company’s
management or persons acting on management’s behalf make forward-looking statements to inform existing and
potential security holders about the Company. These statements may include, but are not limited to, projections and
estimates concerning the timing and success of specific projects and the Company’s future: (1) income, (2) crude oil
and natural gas production, (3) crude oil and natural gas reserves and reserve replacement and (4) capital spending.
Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,”
“expect,” “anticipate,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes.
Sometimes the Company will specifically describe a statement as being a forward-looking statement. In addition,
except for the historical information contained in this Form 10-K, the matters discussed in this Form 10-K are
forward-looking statements. These statements by their nature are subject to certain risks, uncertainties and
assumptions and will be influenced by various factors. Should any of the assumptions underlying a forward-looking
statement prove incorrect, actual results could vary materially.
Noble Energy believes the factors discussed below are important factors that could cause actual results to differ
materially from those expressed in any forward-looking statement made herein or elsewhere by the Company or on its
behalf. The factors listed below are not necessarily all of the important factors. Unpredictable or unknown factors not
discussed herein could also have material adverse effects on actual results of matters that are the subject of forward-
looking statements. Noble Energy does not intend to update its description of important factors each time a potential
important factor arises. The Company advises its stockholders that they should: (1) be aware that important factors not
described below could affect the accuracy of our forward-looking statements, and (2) use caution and common sense
when analyzing our forward-looking statements in this document or elsewhere. All of such forward-looking
statements are qualified in their entirety by this cautionary statement.
Volatility and Level of Hydrocarbon Commodity Prices. Historically, natural gas and crude oil prices have been
volatile. These prices rise and fall based on changes in market supply and demand fundamentals and changes in the
political, regulatory and economic climates and other factors that affect commodities markets generally and are
outside of Noble Energy’s control. Some of Noble Energy’s projections and estimates are based on assumptions as to
the future prices of natural gas and crude oil. These price assumptions are used for planning purposes. The Company
expects its assumptions may change over time and that actual prices in the future may differ from our estimates. Any
substantial or extended change in the actual prices of natural gas and/or crude oil could have a material effect on: (1)
the Company’s financial position and results of operations, (2) the quantities of natural gas and crude oil reserves that
the Company can economically produce, (3) the quantity of estimated proved reserves that may be attributed to its
properties, and (4) the Company’s ability to fund its capital program.
Production Rates and Reserve Replacement. Projecting future rates of crude oil and natural gas production is
inherently imprecise. Producing crude oil and natural gas reservoirs generally have declining production rates.
Production rates depend on a number of factors, including geological, geophysical and engineering issues, weather,
production curtailments or restrictions, prices for natural gas and crude oil, available transportation capacity, market
demand and the political, economic and regulatory climates. Another factor affecting production rates is Noble
Energy’s ability to replace depleting reservoirs with new reserves through exploration success or acquisitions.
Exploration success is difficult to predict, particularly over the short term, where results can vary widely from year to
year. Moreover, the Company’s ability to replace reserves over an extended period depends not only on the total
volumes found, but also on the cost of finding and developing such reserves. Depending on the general price
34
environment for natural gas and crude oil, Noble Energy’s finding and development costs may not justify the use of
resources to explore for and develop such reserves.
Reserve Estimates. Noble Energy’s forward-looking statements are predicated, in part, on the Company’s estimates of
its crude oil and natural gas reserves. All of the reserve data in this Form 10-K or otherwise made by or on behalf of
the Company 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 natural gas and
crude oil reserves. Projecting future rates of production and timing of future development expenditures is also inexact.
Many factors beyond the Company’s control affect these estimates. In addition, the accuracy of any reserve estimate is
a function of the quality of available data and of engineering and geological interpretation and judgment. Therefore,
estimates made by different engineers may vary. The results of drilling, testing and production after the date of an
estimate may also require a revision of that estimate, and these revisions may be material. As a result, reserve
estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered.
Laws and Regulations. Noble Energy’s forward-looking statements are generally based on the assumption that the
legal and regulatory environments will remain stable. Changes in the legal and/or regulatory environments could have
a material effect on the Company’s future results of operations and financial condition. Noble Energy’s ability to
economically produce and sell crude oil, natural gas, methanol and power is affected by a number of legal and
regulatory factors, including federal, state and local laws and regulations in the U.S. and laws and regulations of
foreign nations, affecting: (1) crude oil and natural gas production, (2) taxes applicable to the Company and/or its
production, (3) the amount of crude oil and natural gas available for sale, (4) the availability of adequate pipeline and
other transportation and processing facilities, and (5) the marketing of competitive fuels. The Company’s operations
are also subject to extensive federal, state and local laws and regulations in the U.S. and laws and regulations of
foreign nations relating to the generation, storage, handling, emission, transportation and discharge of materials into
the environment. Noble Energy’s forward-looking statements are generally based upon the expectation that the
Company will not be required, in the near future, to expend cash to comply with environmental laws and regulations
that are material in relation to its total capital expenditures program. However, inasmuch as such laws and regulations
are frequently changed, the Company is unable to accurately predict the ultimate financial impact of compliance.
Drilling and Operating Risks. Noble Energy’s drilling operations are subject to various risks common in the industry,
including cratering, explosions, fires and uncontrollable flows of crude oil, natural gas or well fluids. In addition, a
substantial amount of the Company’s operations are currently offshore, domestically and internationally, and subject
to the additional hazards of marine operations, such as loop currents, capsizing, collision, and damage or loss from
severe weather. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be
curtailed, delayed or canceled as a result of a variety of factors, including drilling conditions, pressure or irregularities
in formations, equipment failures or accidents and adverse weather conditions.
Competition. The Company’s forward-looking statements are generally based on a stable competitive environment.
Competition in the industry is intense. Noble Energy actively competes for reserve acquisitions and exploration leases
and licenses, for the labor and equipment required to operate and develop crude oil and natural gas properties and in
the gathering and marketing of natural gas, crude oil, methanol and power. The Company’s competitors include the
major integrated oil companies, independent crude oil and natural gas concerns, individual producers, natural gas and
crude oil marketers and major pipeline companies, as well as participants in other industries supplying energy and fuel
to industrial, commercial and individual consumers, many of whom have greater financial resources than the
Company.
Noble Energy believes that the location of its properties, its expertise in exploration, drilling and production
operations, the experience of its management and the efforts and expertise of its marketing units generally enable it to
compete effectively. In making projections with respect to numerous aspects of the Company’s business, Noble
Energy generally assumes that there will be no material adverse change in competitive conditions.
35
Item 8.
Financial Statements and Supplementary Data.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Independent Auditors’ Reports ....................................................................................................................... 37
Consolidated Balance Sheets as of December 31, 2002 and 2001 ................................................................. 39
Consolidated Statements of Operations for each of the three years in the period ended
December 31, 2002 ..................................................................................................................................... 40
Consolidated Statements of Cash Flows for each of the three years in the period ended
December 31, 2002 ..................................................................................................................................... 41
Consolidated Statements of Shareholders’ Equity and Other Comprehensive Income
for each of the three years in the period ended December 31, 2002 ........................................................... 42
Notes to Consolidated Financial Statements................................................................................................... 43
Supplemental Oil and Gas Information (Unaudited) ...................................................................................... 62
Supplemental Quarterly Financial Information (Unaudited) .......................................................................... 68
All other financial statement schedules have been omitted because the required information is not present or is not
present in amounts sufficient to require submission of the schedule or because the information required is included in
the financial statements, including the notes thereto.
36
To the Shareholders and Board of Directors of Noble Energy, Inc.:
Independent Auditor’s Report
We have audited the accompanying consolidated balance sheet of Noble Energy, Inc. (a Delaware corporation)
and subsidiaries as of December 31, 2002 and the related consolidated statements of operations, shareholders’ equity
and other comprehensive income, and cash flows for the year then ended. These 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 audit. The financial statements of the Company as of December 31, 2001 and 2000,
and for the two years then ended, were audited by other auditors who have ceased operations. Those auditors
expressed an unqualified opinion on those financial statements dated January 24, 2002.
We conducted our audit in accordance with auditing standards generally accepted in the United States of
America. 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 audit provides a reasonable basis for our opinion.
In our opinion, 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, 2002 and the results of their operations
and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United
States of America.
As discussed above, other auditors who have ceased operations audited the 2001 and 2000 financial statements
of Noble Energy, Inc. As described in “Note 11 - Geographical Data,” the Company changed the composition of its
reportable segments in 2002, and the amounts in the 2001 and 2000 financial statements relating to reportable
segments have been restated to conform to the 2002 composition of reportable segments. We audited the adjustments
that were applied to restate the disclosures for reportable segments reflected in the 2001 and 2000 financial
statements. In our opinion, such adjustments are appropriate and have been properly applied. However, we were not
engaged to audit, review or apply any procedures to the 2001 and 2000 financial statements of Noble Energy, Inc.
other than with respect to such adjustments and, accordingly, we do not express an opinion or any other form of
assurance on the 2001 and 2000 financial statements taken as a whole.
Houston, Texas
February 21, 2003
KPMG LLP
37
1. This report is a copy of a previously issued report (see page 32 of the Company’s Annual Report for
December 31, 2001 on Form 10-K).
2. The predecessor auditor has not reissued this report.
3. The predecessor auditor’s report was issued prior to the restatement referenced in the last paragraph of
the February 21, 2003 Independent Auditor’s Report by KPMG LLP on page 37 of this Form 10-K.
Report of Independent Public Accountants
To the Shareholders and Board of Directors of Noble Affiliates, Inc.:
We have audited the accompanying consolidated balance sheet of Noble Affiliates, Inc. (a Delaware corporation)
and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of operations,
shareholders’ equity and other comprehensive income and cash flows for each of the three years in the period ended
December 31, 2001. These financial statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the 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 provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial
position of Noble Affiliates, Inc. and subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with
accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma
January 24, 2002
38
CONSOLIDATED BALANCE SHEETS
NOBLE ENERGY, INC. AND SUBSIDIARIES
(in thousands, except share amounts)
ASSETS
Current Assets:
Cash and short-term investments
Accounts receivable - trade
Oil and gas hedges receivable
Materials and supplies inventories
Other current assets
Total current assets
Property, Plant and Equipment, at Cost:
Oil and gas mineral interests, equipment and facilities
(successful efforts method of accounting)
Other
Accumulated depreciation, depletion and amortization
Total property, plant and equipment, net
Investment in Unconsolidated Subsidiary, at Cost
Other Assets
Total Assets
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Accounts payable - trade
Short-term note payable
Current installments of long-term debt
Oil and gas hedges payable
Other current liabilities
Income taxes - current
Total current liabilities
Deferred Income Taxes
Other Deferred Credits and Noncurrent Liabilities
Long-term Debt
Shareholders’ Equity:
Preferred stock - par value $1.00; 4,000,000 shares authorized, none issued
Common stock - par value $3.33 1/3; 100,000,000 shares authorized;
59,868,067 and 59,511,323 shares issued in 2002 and 2001, respectively
Capital in excess of par value
Accumulated other comprehensive income (loss)
Retained earnings
Less common stock in treasury at cost
(December 31, 2002 and 2001, 2,505,522 shares)
Total shareholders’ equity
Total Liabilities and Shareholders’ Equity
See accompanying Notes to Consolidated Financial Statements.
December 31,
2002
2001
$
15,442
232,924
10,271
10,663
41,074
310,374
$
73,237
182,979
33,424
10,828
51,103
351,571
4,285,508
48,507
4,334,015
(2,194,230 )
2,139,785
234,668
45,188
$ 2,730,015
3,929,226
45,528
3,974,754
(2,021,543 )
1,953,211
117,735
57,331
$ 2,479,848
$ 351,856
41,919
32,285
36,159
9,535
471,754
201,939
69,820
977,116
$ 270,091
25,000
19,507
25,363
40,624
380,585
176,259
75,629
837,177
199,558
405,271
(14,603 )
458,490
1,048,716
198,369
396,104
5,070
449,985
1,049,528
(39,330 )
1,009,386
$ 2,730,015
(39,330 )
1,010,198
$ 2,479,848
39
CONSOLIDATED STATEMENTS OF OPERATIONS
NOBLE ENERGY, INC. AND SUBSIDIARIES
(in thousands, except per share amounts)
Revenues:
Year ended December 31,
2002
2001
2000
Oil and gas sales and royalties
$ 700,602
$ 871,812
$ 800,594
Gathering, marketing and processing
714,091
721,000
589,933
Electricity sales
Income (loss) from investment in unconsolidated subsidiary
Other income
Total Revenues
Costs and Expenses:
Oil and gas operations
Transportation
Oil and gas exploration
18,257
9,532
1,246
(5,075 )
953
1,489
7,441
1,443,728
1,588,690
1,399,457
133,826
133,549
121,866
16,441
16,012
150,701
152,096
9,241
84,868
Gathering, marketing and processing
703,556
708,292
574,266
Electricity generation
15,946
Depreciation, depletion and amortization
285,286
284,016
230,800
Selling, general and administrative
Interest
Interest capitalized
47,664
64,040
44,164
41,904
(16,331 )
(15,953 )
47,291
37,968
(6,326 )
Total Costs and Expenses
1,401,129
1,364,080
1,099,974
Income Before Taxes
Income Tax Provision:
Current
Deferred
Total Tax Provision
Net Income
Basic Earnings Per Share
Diluted Earnings Per Share
Weighted Average Shares Outstanding:
Basic
Diluted
42,599
224,610
299,483
7,625
17,322
24,947
31,595
59,440
74,616
33,270
91,035
107,886
$
$
$
17,652
$ 133,575
$ 191,597
0.31
0.31
$
$
2.36
2.33
$
$
3.42
3.38
57,196
57,763
56,549
57,303
55,999
56,755
See accompanying Notes to Consolidated Financial Statements.
40
CONSOLIDATED STATEMENTS OF CASH FLOWS
NOBLE ENERGY, INC. AND SUBSIDIARIES
(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
Depreciation, depletion and amortization - electricity generation
Dry hole expense
Amortization of unproved leasehold costs, net
(Gain) loss on disposal of assets
Noncurrent deferred income taxes
(Income) loss from unconsolidated subsidiary
Dividends received from unconsolidated subsidiary
Increase (decrease) in other deferred credits
(Increase) decrease in other
Changes in operating assets and liabilities, not including cash:
(Increase) decrease in accounts receivable
(Increase) decrease in other current assets
Increase (decrease) in accounts payable
Increase (decrease) in other current liabilities
Net Cash Provided by Operating Activities
Cash Flows from Investing Activities:
Capital expenditures
Investment in unconsolidated subsidiary
Proceeds from sale of property, plant and equipment
Distribution from unconsolidated subsidiary
Aspect acquisition
Cash obtained in acquisition
Net Cash Used in Investing Activities
Cash Flows from Financing Activities:
Exercise of stock options
Cash dividends paid
Proceeds from bank debt
Repayment of bank debt
Repayment of notes payable - unconsolidated subsidiary
Repayment of note payable obtained in Aspect acquisition
Purchase of treasury stock
Net Cash Provided by Financing Activities
Increase (Decrease) in Cash and Short-term Cash Investments
Cash and Short-term Cash Investments at Beginning of Year
Cash and Short-term Cash Investments at End of Year
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
Interest (net of amount capitalized)
Income taxes paid (refunded)
Non-cash financing and investing activities:
Issuance of treasury stock for acquisition
Debt assumed in acquisition
Consolidation of AMCCO’s debt (net of discount)
See accompanying Notes to Consolidated Financial Statements.
41
Year ended December 31,
2001
2002
2000
$ 17,652
$ 133,575
$ 191,597
284,016
230,800
285,286
8,458
81,396
21,254
(106)
18,192
(9,532)
17,696
(5,810)
10,942
(49,945)
21,972
81,764
5,072
504,291
(595,739)
(7,652)
20,363
5,500
(577,528)
10,356
(9,147)
158,669
(124,929)
99,684
17,213
(2,098)
59,212
5,075
13,990
(2,224)
57,973
(64,951)
(17,960)
52,267
635,772
(738,706)
(48,651)
1,434
(107,078)
9,286
(883,715)
16,675
(9,042)
675,000
(375,000)
(19,507)
(9,605)
15,442
(57,795)
73,237
$ 15,442
298,028
50,085
23,152
$ 73,237
38,463
16,075
(3,799)
33,973
(1,489)
7,762
(3,747)
(137,049)
3,557
198,871
(4,680)
570,334
(536,901)
(57,045)
12,608
(581,338)
13,717
(8,958)
137,000
(57,000)
(23,245)
(30,283)
31,231
20,227
2,925
$ 23,152
$ 26,321
$ (40,394)
$ 26,590
$ 66,131
$ 32,976
$ 56,890
$ 14,238
$ 40,043
$ 122,945
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND
OTHER COMPREHENSIVE INCOME
NOBLE ENERGY, INC. AND SUBSIDIARIES
(in thousands)
Comprehensive
Income (Loss)
Common
Stock
Capital in
Excess of
Par Value
Accumulated
Other
Retained Comprehensive
Income (Loss)
Earnings
Treasury
Stock
At Cost
Total
Shareholders’
Equity
$683,609
191,597
(30,283)
13,717
(8,958)
$849,682
133,575
5,070
14,238
16,675
(9,042)
December 31, 1999
Net Income
Purchase of treasury stock
Exercise of stock options
Cash dividends
($.16 per share)
December 31, 2000
Net Income
Hedge derivatives marked
$195,231 $360,983 $142,813
191,597
1,441
12,276
(8,958)
$196,672 $373,259 $325,452
133,575
$ 133,575
$(15,418)
(30,283)
$(45,701)
to market
5,070
5,070
Treasury stock issued
for acquisition
Exercise of stock options
Cash dividends
($.16 per share)
Total
December 31, 2001
Net Income
Reclassification of
unrealized gains on
hedges to net income,
net of $.5 income tax
Change in fair value of
cash flow hedges,
net of income tax
Exercise of stock options
Cash dividends
($.16 per share)
Total
December 31, 2002
1,697
7,867
14,978
6,371
$ 138,645
(9,042)
$ 17,652
$198,369 $396,104 $449,985
17,652
$5,070 $(39,330)
$1,010,198
17,652
1
(19,674)
$
(2,021)
1
1
1,189
9,167
(19,674)
(9,147)
(19,674)
10,356
(9,147)
$199,558 $405,271 $458,490 $(14,603) $(39,330)
$1,009,386
See accompanying Notes to Consolidated Financial Statements.
42
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollar amounts in tables, unless otherwise indicated, are in thousands, except per share amounts)
Note 1 - Summary of Significant Accounting Policies
Basis of Presentation and Consolidation
Accounting policies used by Noble Energy, Inc. and subsidiaries reflect industry practices and conform to accounting
principles generally accepted in the United States of America. The more significant of such policies are briefly
discussed below. The consolidated accounts include Noble Energy, Inc. (the “Company” or “Noble Energy”) and the
consolidated accounts of its wholly-owned subsidiaries. Effective December 31, 2001, Energy Development
Corporation (“EDC”), a previously wholly-owned subsidiary of Samedan Oil Corporation (“Samedan”), was merged
into Samedan, another previously wholly-owned subsidiary. Effective December 31, 2002, Samedan was merged into
Noble Energy, Inc. Also effective December 31, 2002, Noble Trading, Inc. (“NTI”) was merged into Noble Gas
Marketing, Inc. (“NGM”) under the new name of Noble Energy Marketing, Inc. (“NEMI”). Listed below are
consolidated entities at December 31, 2002. All significant intercompany balances and transactions have been
eliminated upon consolidation.
NOBLE ENERGY, INC.
LaTex Resources Inc.
Noble Energy Marketing, Inc.
Noble Gas Pipeline, Inc.
NPM, Inc.
Samedan North Sea, Inc.
Samedan of North Africa, Inc.
EDC Ireland
Samedan International
Machalapower Cia. Ltda.
Samedan, Mediterranean Sea
Samedan Transfer Sub
Samedan Vietnam Limited
Samedan, Mediterranean Sea, Inc.
Samedan of Tunisia, Inc.
Samedan Oil of Canada, Inc.
Samedan Oil of Indonesia, Inc.
Samedan Pipe Line Corporation
Samedan Royalty Corporation
EDC Australia, Ltd.
EDC Ecuador Ltd.
EDC Ecuador Limited
EDC Portugal Ltd.
EDC (UK) Limited
EDC (Denmark) Inc.
EDC (Europe) Limited
EDC (ISE) Limited
EDC (Oilex) Limited
Brabant Oil Limited
Energy Development Corporation (Argentina), Inc.
Energy Development Corporation (China), Inc.
Energy Development Corporation (HIPS), Inc.
Gasdel Pipeline System Incorporated
HGC, Inc.
Producers Service, Inc.
43
Nature of Operations
The Company is an independent energy company engaged, directly or through its subsidiaries or various arrangements
with other companies, in the exploration, development, production and marketing of crude oil and natural gas. The
Company has exploration, exploitation and production operations domestically and internationally. The domestic areas
consist of: offshore in the Gulf of Mexico and California; the Gulf Coast Region (Louisiana, New Mexico and Texas);
the Mid-Continent Region (Oklahoma and Kansas); and the Rocky Mountain Region (Colorado, Montana, North
Dakota, Wyoming and California). The international areas of operations include Argentina, China, Ecuador,
Equatorial Guinea, the Mediterranean Sea (Israel), the North Sea (Denmark, Netherlands and United Kingdom) and
Vietnam. The Company also markets domestic crude oil and natural gas production through NEMI.
Use of Estimates
The preparation of the consolidated financial statements requires management of the Company to make a number of
estimates and assumptions relating to the reported amount 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. The Company’s estimates of crude oil and natural gas reserves are the most
significant. 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 natural gas and crude oil 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. Other items
subject to estimates and assumptions include the carrying amount of property, plant and equipment; valuation
allowances for receivables, inventories and deferred income tax assets; environmental liabilities; valuation of
derivative instruments; and assets and obligations related to employee benefits. Actual results could differ from those
estimates.
Foreign Currency Translation
The U.S. dollar is considered the primary currency for each of the Company’s international operations. Transactions
that are completed in a foreign currency are translated into U.S. dollars and recorded in the financial statements.
Translation gains or losses were not material in any of the periods presented and are included in other income on the
statement of operations.
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, with cost being determined by the first-in, first-out method.
Property, Plant and Equipment
The Company accounts for its 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 developed crude oil and natural gas reserves on a property-by-property basis as estimated by Company
engineers. Through December 31, 2002, estimated future restoration and abandonment costs are recorded by charges
to DD&A expense over the productive lives of the related properties. The Company has provided $84.1 million for
such future costs classified with accumulated DD&A in the December 31, 2002 balance sheet. The total estimated
future dismantlement and restoration costs of $206.6 million, which consists of $188.7 million for the United States
and $17.9 million for the North Sea, are included in future production and development costs for purposes of
44
estimating the future net revenues relating to the Company’s proved reserves. 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.
Individually significant unproved crude oil and natural gas properties are periodically assessed for impairment of
value and a loss is recognized at the time of impairment by providing an impairment allowance. Other unproved
properties are amortized on a composite method based on the Company’s experience of successful drilling and
average holding period. Geological and geophysical costs, delay rentals and costs to drill exploratory wells that do not
find proved reserves are expensed. Repairs and maintenance are expensed as incurred.
Proved crude oil and natural gas properties and other long-lived assets are periodically assessed to determine if
circumstances indicate that the carrying amount of an asset may not be recoverable. SFAS No. 144, “Accounting for
the Impairment or Disposal of Long-Lived Assets,” was issued in August 2001. This statement addresses financial
accounting and reporting for the impairment or disposal of long-lived assets. This statement supersedes SFAS No.
121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.” This
statement requires (a) recognition of an impairment loss only if the carrying amount of a long-lived asset is not
recoverable from its undiscounted cash flows and (b) measurement of an impairment loss as the difference between
the carrying amount and fair value of the asset. The Company adopted the statement January 1, 2002 with no material
impact on the Company’s results of operations or financial position.
Income Taxes
Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized
for the future tax consequences attributable to differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. 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 enactment date.
Capitalization of Interest
The Company capitalizes interest costs associated with the development and construction of significant properties or
projects.
Statement of Cash Flows
For purposes of reporting cash flows, cash and short-term investments include cash on hand and investments
purchased with original maturities of three months or less.
45
Basic Earnings Per Share 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 stock
options. The following table summarizes the calculation of basic EPS and diluted EPS components as of
December 31:
2002
2001
2000
(in thousands
except per share amounts)
Net income/shares
Basic EPS
Net income/shares
Effect of Dilutive Securities
Stock options
Adjusted net income
and shares
Diluted EPS
Income
Shares
(Numerator) (Denominator) (Numerator) (Denominator) (Numerator) (Denominator)
55,999
$133,575
$191,597
$17,652
Income
Income
57,196
56,549
Shares
Shares
$.31
$2.36
$3.42
$17,652
57,196
$133,575
56,549
$191,597
55,999
567
754
756
$17,652
57,763
$133,575
57,303
$191,597
56,755
$.31
$2.33
$3.38
The table below reflects the amount of options not included in the EPS calculation above, as they were antidilutive.
Options excluded from dilution calculation
Range of exercise prices
Weighted average exercise price
Accounting for Employee Stock-Based Compensation
2002
2,229,978
$35.40 - $43.21
$39.77
2001
1,485,303
$38.88 - $43.21
$41.29
2000
1,633,149
$35.94 - $40.38
$38.39
At December 31, 2002, the Company has two stock-based employee compensation plans, which are described more
fully in “Note 5 - Common Stock, Stock Options and Stockholder Rights.” The Company accounts for those plans
under the intrinsic value recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock
Issued to Employees,” and related Interpretations. At issuance, stock-based employee compensation cost was reflected
in net income, as all options granted under those plans had an exercise price equal to the market value of the
underlying common stock on the date of grant. The following table illustrates the effect on net income and earnings
per share if the Company had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-
Based Compensation,” to stock-based employee compensation.
(in thousands except per share amounts)
Net income, as reported
Add: Stock-based compensation cost recognized, net of
related tax effects
Deduct: Total stock-based employee compensation expense
determined under fair value based method for all awards,
net of related tax effects
Pro forma net income
Earnings per share:
Basic - as reported
Basic - pro forma
Diluted - as reported
2002
$ 17,652
2001
$133,575
2000
$191,597
392
477
(6,394)
$ 11,650
(7,538)
$126,037
(8,170)
$183,904
$
$
$
.31
.20
.31
$
$
$
2.36
2.23
2.33
$
$
$
3.42
3.28
3.38
46
Diluted - pro forma
$
.20
$
2.20
$
3.24
47
Fair value estimates are based on several assumptions and should not be viewed as indicative of the operations of the
Company in future periods. The fair value of each option grant is estimated on the date of grant using the
Black-Scholes option pricing model with the following weighted-average assumptions used for grants in 2002, 2001
and 2000, respectively, as follows:
(amounts expressed in percentages)
Interest rate
Dividend yield
Expected volatility
Expected life
2002
4.78
.43
40.26
9.73
2001
5.46
.40
38.19
9.64
2000
6.25
.40
51.67
9.71
The weighted average fair value of options granted using the Black-Scholes option pricing model for 2002, 2001 and
2000, respectively, is as follows:
Black-Scholes model weighted average fair value
option price
Revenue Recognition and Gas Imbalances
2002
2001
2000
$18.14
$23.86
$16.66
Noble Energy generally recognizes revenue when the product is delivered to a third-party purchaser.
NEMI records third-party sales, including derivative transactions, as gathering, marketing and processing revenues.
NEMI records the amount paid to third parties as gathering, marketing and processing costs and expenses.
The Company follows the entitlements method of accounting for its natural gas imbalances. Natural gas imbalances
occur when the Company sells more or less natural gas than it is entitled to under its ownership percentage of total
natural gas production. Any excess amount received above the Company’s share is treated as a liability. If less than the
Company’s entitlement is received, the underproduction is recorded as a receivable. The Company records the non-
current liability in other deferred credits and non-current liabilities, and the current liability in other current liabilities.
The Company’s natural gas imbalance liabilities were $15.4 million and $15.5 million for 2002 and 2001,
respectively. The Company records the non-current receivable in other assets and the current receivable in other
current assets. The Company’s natural gas imbalance receivables were $20.1 million and $20.9 million for 2002 and
2001, respectively, and are valued at the amount that is expected to be received.
Derivatives and Hedging Activities
The Company, directly or through its subsidiaries, from time to time, uses various hedging arrangements in connection
with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such
arrangements include fixed price hedges, costless collars and other contractual arrangements. Although these hedging
arrangements expose the Company to credit risk, the Company monitors the creditworthiness of its counterparties and
believes that losses from nonperformance are unlikely to occur. Hedging gains and losses related to the Company’s
crude oil and natural gas production are recorded in oil and gas sales and royalties.
The FASB issued SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” in June 1998. The
Statement established accounting and reporting standards requiring every derivative instrument (including certain
derivative instruments embedded in other contracts) to be recorded in the balance sheet as either an asset or liability
measured at its fair value. The Statement requires that changes in the derivative’s fair value be recognized currently in
earnings unless specific hedge accounting criteria are met wherein gains and losses are reflected in shareholders’
equity as other comprehensive income until the hedged item is recognized. Special accounting for qualifying hedges
48
allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations, and
requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge
accounting.
The Company adopted SFAS No. 133 effective January 1, 2001. The adoption of this statement did not have a
material impact on the Company’s results of operations or financial position, as of the date of adoption. At
December 31, 2002, the Company recorded crude oil and natural gas hedge liabilities of $22.5 million and other
comprehensive loss, net of tax, of $14.6 million related to the Company’s hedging contracts.
Self-Insurance
The Company self-insures the medical and dental coverage provided to certain of its employees, certain workers’
compensation and the first $250,000 of its general liability coverage.
Liabilities are accrued for self-insured claims when sufficient information is available to reasonably estimate the
amount of the loss.
Unconsolidated Subsidiary
Prior to January 2002, AMCCO was a 50 percent owned joint venture that owned an indirect 90 percent interest in
AMPCO, which completed construction of a methanol plant in Equatorial Guinea in the second quarter of 2001.
During 1999, AMCCO issued $125 million Series A-1 and $125 million Series A-2 senior secured notes due
December 15, 2004 to fund the remaining construction payments. On January 2, 2002, the Company’s partner in
AMCCO directed AMCCO to sell 50 percent of its interest in AMPCO as a component of the partner’s sale of its
Equatorial Guinea assets. The proceeds of the AMPCO sale were used to repay in full AMCCO’s $125 million Series
A-1 Notes on January 28, 2002 and to make a distribution to the Company’s partner. Since the Company’s partner in
AMCCO no longer retains an economic interest in AMPCO, the Company began consolidating AMCCO’s debt in
2002, thereby including the $125 million Series A-2 Notes in the Company’s balance sheet effective January 28, 2002.
The terms of the $125 million Series A-2 Notes remain unchanged. The Company accounts for its investment in
unconsolidated subsidiary under the equity method of accounting. AMPCO is an integral component of the
Company’s natural gas operations as AMPCO’s function is to convert a portion of the Company’s natural gas reserves
to methanol for sale. For more information, see “Note 9 - Unconsolidated Subsidiary” of this Form 10-K.
Reclassification
Certain reclassifications have been made to the 2000 and 2001 consolidated financial statements to conform to the
2002 presentation. These reclassifications are not material to the Company’s financial position.
Recently Issued Pronouncements
SFAS No. 143, “Accounting for Asset Retirement Obligations,” was issued in June 2001. This statement addresses
financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. This statement requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as
part of the carrying cost of the asset. The Company adopted SFAS No. 143 on January 1, 2003 and will recognize, as
the fair value of asset retirement obligations, $99.7 million related to the United States and $10.0 million related to the
North Sea. The Company’s accumulated provision for future retirement obligations was $84.1 million at December
31, 2002. The Company has not determined the cumulative effect of adoption of this standard. The expected future
retirement obligation for the United States is $188.7 million and for the North Sea is $17.9 million. The difference
between the expected future retirement obligation and the fair value of the retirement obligation will be expensed
beginning in 2003 based on the credit-adjusted risk-free rate of 8.5 percent until the asset retirement date.
49
SFAS No. 148, “Accounting for Stock-Based Compensation,” was issued in December 2002. This statement amends
SFAS No. 123, “Accounting for Stock-Based Compensation,” to provide for alternative methods of transition for an
entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation.
It also amends the disclosure provisions of that statement to require prominent disclosure about the effects on reported
net income of an entity’s accounting policy decisions with respect to stock-based employee compensation.
The Company currently accounts for stock-based employee compensation plans under the recognition and
measurement principles of the APB Opinion No. 25, “Accounting for Stock Issued to Employees.” The Company has
not determined if it will adopt the fair value provisions of SFAS No. 123.
In June 2002, the EITF reached a consensus on certain issues contained in Topic 02-03, “Recognition and Reporting
of Gains and Losses on Energy Trading Contracts” under EITF Issue No. 98-10, “Accounting for Contracts Involved
in Energy Trading and Risk Management Activities.” While the Company does not engage in material energy trading
activities, the EITF has expanded its definition of energy trading activities to include the marketing activities in which
the Company is engaged. As of January 1, 2003, the Company will present its gathering, marketing and processing
activities in the statement of operations for all periods on a net rather than a gross basis. The change will significantly
decrease reported marketing sales and purchases, but will have no effect on operating income or cash flow.
Note 2 - Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of 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, Short-Term Investments, Accounts Receivable and Accounts Payable
The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.
Crude Oil and Natural Gas Price Hedge Agreements
The fair value of crude oil and natural gas price hedges is the estimated amount the Company would receive or pay to
terminate the hedge agreements at the reporting date taking into account creditworthiness of the hedging parties.
Long-Term Debt
The fair value of the Company’s long-term debt is estimated based on the quoted market prices for the same or similar
issues or on the current rates offered to the Company for debt of the same remaining maturities.
The carrying amounts and estimated fair values of the Company’s financial instruments, including current items, as of
December 31, for each of the years are as follows:
(in thousands)
Crude oil and natural gas price hedge agreements
Long-term debt
2002
2001
Carrying
Amount
$
(22,520)
$ (1,025,246)
Fair
Value
$
(22,520)
$ (1,039,216)
Carrying
Amount
$
16,032
$ (861,015)
Fair
Value
$
16,032
$ (871,540)
50
Note 3 - Debt
A summary of debt at December 31 follows:
(in thousands)
December 31, 2002
December 31, 2001
$400 million Credit Agreement, maturity date
November 2006
Note obtained in Aspect acquisition, due May 2004
7 1/4% Notes Due 2023
8% Senior Notes Due 2027
7 1/4% Senior Debentures Due 2097
AMCCO Note, due December 2004
Israel Note, due 2003 and 2004
Outstanding debt
Less: unamortized discount
current installment of long-term debt
Long-term debt
Debt
$ 380,000
11,508
100,000
250,000
100,000
125,000
58,738
1,025,246
6,211
41,919
$ 977,116
Percentage
Interest
Rate
3.00
6.25
7.25
8.00
7.25
Percentage
Interest
Rate
2.47
6.25
7.25
8.00
7.25
8.95
2.18
Debt
$ 380,000
31,015
100,000
250,000
100,000
861,015
4,331
19,507
$ 837,177
The Company’s total long-term debt, net of unamortized discount, at December 31, 2002, was $977 million compared
to $837 million at December 31, 2001. If the $125 million AMCCO debt had been included, the total long-term debt
would have been $962 million at December 31, 2001. The ratio of debt-to-book capital (defined as the Company’s
total debt plus its equity) was 50 percent at December 31, 2002, compared with 47 percent at December 31, 2001.
The Company entered into a new $400 million five-year credit agreement on November 30, 2001, with certain
commercial lending institutions, which exposes the Company to the risk of earnings or cash flow loss due to changes
in market interest rates. The interest rate is based upon a Eurodollar rate plus a range of 60 to 145 basis points
depending upon the percentage of utilization and credit rating. At December 31, 2002, there was $380 million
borrowed against this credit agreement, which has a maturity date of November 30, 2006.
The Company also entered into a new $200 million 364-day credit agreement on November 27, 2002 with certain
commercial lending institutions which exposes the Company to the risk of earnings or cash flow loss due to changes
in market interest rates. The interest rate is based upon a Eurodollar rate plus a range of 62.5 to 150 basis points
depending upon the percentage of utilization and credit rating. At December 31, 2002, there were no amounts
outstanding under this credit agreement. The agreement has a maturity date of November 26, 2003 for the revolving
commitment and a maturity date of November 25, 2004 for the term commitment that includes any balance remaining
after the revolving commitment matures.
Financial covenants on both the $400 million and $200 million credit facilities include the following: (a) the ratio of
EBITDAX to total interest expense for any consecutive period of four fiscal quarters ending on the last day of a fiscal
quarter may not be less than 4.0 to 1.0; (b) the total debt to capitalization ratio, expressed as a percentage, may not
exceed 60 percent at any time; and (c) the total asset value of the Company’s restricted subsidiaries may not be less
than $800 million at any time.
The Company had no short-term borrowings outstanding on December 31, 2002. The Company had a $25 million
short-term note payable outstanding December 31, 2001, which was repaid January 28, 2002. The note was an
uncommitted facility with an interest rate of 3.25 percent for the period December 28, 2001 to January 28, 2002.
51
Note 4 - Income Taxes
The following table details the difference between the federal statutory tax rate and the effective tax rate for the years
ended December 31:
(amounts expressed in percentages)
Statutory rate (benefit)
Effect of:
State taxes, net of federal benefit
Difference between U.S. and foreign rates
Other, net
Effective rate
2002
35.0
1.1
24.5
(2.0)
58.6
2001
35.0
.3
4.9
.4
40.6
2000
35.0
.3
.2
.5
36.0
The net current deferred tax asset (liability) in the following table is classified as other current assets in the
consolidated balance sheet. The tax effects of temporary differences that gave rise to deferred tax assets and liabilities
as of December 31 were:
(in thousands)
U.S. and State Current Deferred Tax Assets (Liabilities):
Accrued expenses
Deferred income
Allowance for doubtful accounts
Marked to market - hedging contracts
Other
Net U.S. and State Current Deferred Tax Assets (Liabilities)
U.S. and State Non-current Deferred Tax Assets (Liabilities):
Property, plant and equipment, principally due to
differences in depreciation, amortization, lease
impairment and abandonments
Accrued expenses
Deferred income
Allowance for doubtful accounts
Foreign and state income tax accruals
Post retirement benefits
Other
Net U.S. and State Non-current Deferred Tax Assets (Liabilities)
Total Net U.S. and State Deferred Tax Assets (Liabilities)
Foreign Non-current Deferred Tax Assets (Liabilities):
Property, plant and equipment of
foreign operations
Foreign loss carryforward
Net Foreign Non-current Deferred Tax Assets (Liabilities)
Valuation allowance
Total Net Deferred Tax Assets (Liabilities)
2002
2001
$
980
387
353
7,864
9,584
$
15
626
226
(2,730)
(17)
(1,880)
(183,338)
4,777
4,594
5,935
11,940
9,668
(245)
(146,669)
(137,085)
(177,382)
7,125
6,029
5,767
11,627
2,489
(245)
(144,590)
(146,470)
(55,270)
4,416
(50,854)
(4,416)
$(192,355)
(31,669)
2,745
(28,924)
(2,745)
$(178,139)
The components of income (loss) from operations before income taxes as of December 31 for each year are as
follows:
(in thousands)
Domestic
Foreign
Total
$
2002
3,067
39,532
$ 42,599
2001
$ 241,479
(16,869)
$ 224,610
2000
$ 268,489
30,994
$ 299,483
52
The income tax provision (benefit) relating to operations consists of the following for the years ended December 31:
(in thousands)
U.S. current
U.S. deferred
State current
State deferred
Foreign current
Foreign deferred
Total
2002
$ (7,945)
1,421
895
(212)
14,675
16,113
$ 24,947
2001
$ 24,743
53,591
651
360
6,200
5,490
$ 91,035
2000
$ 65,358
32,311
917
334
8,341
625
$107,886
In assessing the realizability of deferred tax assets, management considers 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 the generation of future taxable income during the periods in which those temporary differences become
deductible. Management considers 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, management
believes it is more likely than not that the Company will realize the benefits of these deductible differences, net of the
existing valuation allowances at December 31, 2002. The amount of the deferred tax asset considered realizable,
however, could be reduced in the near term if estimates of future taxable income during the carryforward period are
reduced.
Note 5 - Common Stock, Stock Options and Stockholder Rights
The Company has two stock option plans, the 1992 Stock Option and Restricted Stock Plan (“1992 Plan”) and the
1988 Non-Employee Director Stock Option Plan (“1988 Plan”). The Company accounts for these plans under APB
Opinion No. 25.
Under the Company’s 1992 Plan, the Board of Directors may grant stock options and award restricted stock. No
restricted stock has been issued under the 1992 Plan. Since the adoption of the 1992 Plan, stock options have been
issued at the market price on the date of grant. The earliest the granted options may be exercised is over a three year
period at the rate of 33 1/3% each year commencing on the first anniversary of the grant date. The options expire ten
years from the grant date. The 1992 Plan was amended in 2000, by a vote of the shareholders, to increase the
maximum number of shares of common stock that may be issued under the 1992 Plan to 6,500,000 shares. At
December 31, 2002, the Company had reserved 5,042,040 shares of common stock for issuance, including 1,079,604
shares available for grant, under its 1992 Plan.
The Company’s 1988 Plan allows stock options to be issued to certain non-employee directors at the market price on
the date of grant. The options may be exercised one year after issue and expire ten years from the grant date. The 1988
Plan provides for the grant of options to purchase a maximum of 550,000 shares of the Company’s authorized but
unissued common stock. The 1988 Plan was amended at the shareholders’ annual meeting on April 24, 2001 to
provide for the granting of a consistent number of stock options to each non-employee director annually (10,000 stock
options for the first year of service and 5,000 stock options for each year thereafter) and to change the annual grant
date to February 1, commencing February 1, 2002. At December 31, 2002, the Company had reserved 321,571 shares
of common stock for issuance, including 89,786 shares available for grant, under its 1988 Plan.
The Company adopted a stockholder rights plan on August 27, 1997, designed to assure that the Company’s
stockholders receive fair and equal treatment in the event of any proposed takeover of the Company and to guard
against partial tender offers and other abusive takeover tactics to gain control of the Company without paying all
stockholders a fair price. The rights plan was not adopted in response to any specific takeover proposal. Under the
53
rights plan, the Company declared a dividend of one right (“Right”) on each share of Noble Energy, Inc. common
stock. Each Right will entitle the holder to purchase one one-hundredth of a share of a new Series A Junior
Participating Preferred Stock, par value $1.00 per share, at an exercise price of $150.00. The Rights are not currently
exercisable and will become exercisable only in the event a person or group acquires beneficial ownership of 15
percent or more of Noble Energy, Inc. common stock. The dividend distribution was made on September 8, 1997, to
stockholders of record at the close of business on that date. The Rights will expire on September 8, 2007.
A summary of the status of Noble Energy’s stock option plans as of December 31, 2000, 2001 and 2002, and changes
during each of the years then ended, is presented below.
Options Outstanding
Options Exercisable
Outstanding at December 31, 1999
Options granted
Options exercised
Options canceled
Outstanding at December 31, 2000
Options granted
Options exercised
Options canceled
Outstanding at December 31, 2001
Options granted
Options exercised
Options canceled
Outstanding at December 31, 2002
Number
Outstanding
3,484,938
774,343
(432,199)
(105,977)
3,721,105
723,400
(509,161)
(81,267)
3,854,077
732,500
(356,744)
(35,612)
4,194,221
Exercise
Price
$ 29.98
$ 24.19
$ 24.43
$ 29.11
$ 29.44
$ 42.77
$ 24.97
$ 33.11
$ 32.46
$ 32.66
$ 21.56
$ 37.02
$ 33.38
Number
Exercisable
Weighted
Average
Exercise
Price
2,203,146
$ 31.14
2,408,522
$ 32.08
2,530,285
$ 32.10
2,871,943
$ 32.84
The following table summarizes information about Noble Energy’s stock options which were outstanding, and those
which were exercisable, as of December 31, 2002.
Options Outstanding
Options Exercisable
Range of
Exercise Prices
Number
Outstanding
$17.28 - $21.61
$21.61 - $25.93
$25.93 - $30.25
$30.25 - $34.57
$34.57 - $38.89
$38.89 - $43.21
833,264
185,145
126,834
785,075
742,924
1,520,979
4,194,221
Weighted
Average
Remaining
Life
6.0 Years
1.9 Years
2.3 Years
8.5 Years
4.9 Years
5.2 Years
5.7 Years
Weighted
Average
Exercise
Price
$20.06
$24.52
$27.41
$32.32
$36.34
$41.36
$33.38
Number
Exercisable
678,310
185,145
126,834
79,958
702,924
1,098,772
2,871,943
Weighted
Average
Exercise
Price
$20.06
$24.52
$27.41
$31.27
$36.24
$40.69
$32.84
Compensation expense totaling $643,170 and $781,275 was recognized in 2002 and 2000, respectively, due to the
accelerated vesting of stock options as a result of the retirement of certain employees.
54
Note 6 - Employee Benefit Plans
Pension Plan and Other Postretirement Benefit Plans
The Company has a non-contributory defined benefit pension plan covering substantially all of its domestic
employees. The benefits are based on an employee’s years of service and average earnings for the 60 consecutive
calendar months of highest compensation. The Company also has an unfunded restoration plan to ensure payments of
amounts for which employees are entitled under the provisions of the pension plan, but which are subject to
limitations imposed by federal tax laws. The Company’s funding policy has been to make annual contributions equal
to the actuarially computed liability to the extent such amounts are deductible for income tax purposes. Plan assets
consist of equity securities and fixed income investments.
The Company sponsors other plans for the benefit of its employees and retirees. These plans include health care and
life insurance benefits. The following table reflects the required disclosures on the Company’s pension and other
postretirement benefit plans at December 31:
Pension Benefits
Other Benefits
2002
2001
2002
2001
(in thousands)
Change in benefit obligation
Benefit obligation at beginning of year
Adjustment for contributions paid in 2000
Service cost
Interest cost
Amendments
Plan participants’ contributions
Actuarial (gain) loss
Benefits paid
Benefit obligation at year end
Change in plan assets
Fair value of plan assets at beginning of year
Actual return on plan assets
Employer contribution
Benefits paid
Fair value of plan at end of year
Fund status
Unrecognized net actuarial loss (gain)
Unrecognized prior service cost
Unrecognized net transition obligation (assets)
Prepaid (accrued) benefit costs
Components of net periodic benefit cost
Service cost
Interest cost
Expected return on plan assets
Transition (assets) obligation recognition
Amortization of prior service cost
Recognized net actuarial loss (gain)
Net periodic benefit cost
Weighted-average assumptions as of December 31,
Discount rate
Expected return on plan assets
Rate of compensation increase
$ 89,587
4,986
7,071
380
8,439
(4,239)
$106,224
$ 53,570
(3,471)
10,800
(4,239)
$ 56,660
$ (49,564)
23,366
2,525
1,167
$ (22,506)
$ 4,986
7,071
(5,474)
24
306
845
$ 7,758
$ 76,623
(54)
3,790
6,218
6,882
(3,872)
$ 89,587
$ 55,487
(1,541)
3,497
(3,873)
$ 53,570
$ (36,017)
6,826
2,451
1,191
$ (25,549)
$ 3,790
6,218
(4,899)
24
292
(66)
$ 5,359
$ 2,688
$ 2,718
346
314
90
2,849
(146)
$ 6,141
220
193
71
(333)
(181)
$ 2,688
$
$
146
(146)
$
$ (6,141)
2,472
(244)
180
(180)
$
$ (2,688)
(304)
(274)
$ (3,913)
$ (3,266)
$
346
314
$
220
193
$
(30)
73
703
6.75%
4.00%
(30)
(10)
373
$
7.25%
5.50%
6.75%
8.50%
4.00%
7.25%
8.50%
4.75%
55
The following table reflects the aggregate pension obligation components for the defined benefit pension plan and the
restoration benefit plan, which are aggregated in the previous tables, at December 31:
(in thousands)
Aggregated pension benefits
Aggregate fair value of plan assets
Aggregate accumulated benefit obligation
Fund status of net periodic
benefit assets (obligation)
Defined Benefit
Pension Plan
Restoration
Benefit Plan
2002
2001
2002
2001
$ 56,660
86,083
$ 53,570
73,868
$
$
20,141
15,719
$ (29,423)
$ (20,298)
$ (20,141)
$ (15,719)
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 results:
(in thousands)
Total service and interest cost components
Total postretirement benefit obligation
Employee Savings Plan (“ESP”)
1-Percentage-
Point increase
$ 733
$6,766
1-Percentage-
Point decrease
$ 598
$5,591
The Company has an ESP that is a defined contribution plan. Participation in the ESP is voluntary and all regular
employees of the Company are eligible to participate. The Company may match up to 100 percent of the participant’s
contribution not to exceed six percent of the employee’s base compensation. The following table indicates the
Company’s contribution for the years ended December 31:
(in thousands)
Employers’ plan contribution
2002
$2,302
2001
$2,145
2000
$1,858
Note 7 - Additional Balance Sheet and Statement of Operations Information
Included in accounts receivable-trade is an allowance for doubtful accounts at December 31:
(in thousands)
Allowance for doubtful accounts
Other current assets included the following at December 31:
(in thousands)
Deferred tax asset (liability)
Prepaid federal income taxes
Other current liabilities included the following at December 31:
(in thousands)
Gas imbalance liabilities
Accrued interest payable
Louisiana workers compensation
56
2002
1,510
$
2001
638
$
2002
9,584
$
2001
$
(1,880)
$ 66,131
2002
$
1,090
$ 11,178
7,611
$
2001
$
1,593
$ 10,692
6,433
$
Crude oil and natural gas operations expense included the following for the years ended December 31:
(in thousands)
Lease operating expense
Workover expense
Production taxes
Total operations expense
2002
$ 111,055
8,455
14,316
$ 133,826
2001
$ 109,626
15,094
8,829
$ 133,549
2000
$ 90,478
21,124
10,264
$ 121,866
Crude oil and natural gas exploration expense included the following for the years ended December 31:
(in thousands)
Dry hole expense
Unproved lease amortization
Seismic
Other
Total exploration expense
2002
$ 81,396
21,254
20,492
27,559
$ 150,701
2001
$ 99,684
17,213
15,607
19,592
$ 152,096
2000
$ 38,463
16,075
18,738
11,592
$ 84,868
During the past three years, there was no third-party purchaser that accounted for more than 10 percent of the annual
total crude oil and natural gas sales and royalties.
Note 8 - Derivatives and Hedging Activities
During 2002, the Company entered into various natural gas costless collars, natural gas costless collar combinations
and crude oil costless collar transactions related to its production. The table below depicts the various transactions for
2002.
Natural Gas
Crude Oil
Hedge MMBTUpd
Floor price range
Ceiling price range
Percent of daily production
Gain (loss) per Mcf
170,274
$2.00 - $3.50
$2.45 - $5.10
44%
$.03
Hedge Bpd
Floor price range
Ceiling price range
Percent of daily production
Gain (loss) per Bbl
5,247
$23.00 - $24.00
$29.30 - $30.10
15%
$0
As of December 31, 2002, the Company had entered into costless collars related to its natural gas and crude oil
production to support the Company’s investment program as follows:
Natural Gas
Crude Oil
Production
Period
1Q 2003
2Q 2003
3Q 2003
4Q 2003
MMBTU
Per Day
185,000
185,000
185,000
185,000
Price
Per MMBTU
Floor - Ceiling
$3.87 - $4.82
$3.43 - $4.57
$3.43 - $4.60
$3.43 - $4.84
Bbls
Per Day
15,000
15,000
10,000
10,000
Price
Per Bbl
Floor - Ceiling
$23.00 - $28.63
$23.00 - $28.63
$23.00 - $27.95
$23.00 - $27.95
The contracts entitle the Company (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 last scheduled NYMEX
trading day applicable for each calculation period is less than the floor price. The Company would pay the
counterparty if the settlement price for the last scheduled NYMEX trading day applicable for each calculation period
is more than the ceiling price. The amount payable by the floating price payor, if the floating price is above the ceiling
price, is the product of the notional quantity per calculation period and the excess, if any, of the floating price over the
57
ceiling price in respect of each calculation period. The amount payable by the fixed price payor, if the floating price is
below the floor price, is the product of the notional quantity per calculation period and the excess, if any, of the floor
price over the floating price in respect of each calculation period.
During 2001, the Company had natural gas costless collars for the fourth quarter of 2001 for 50,000 MMBTU of
natural gas per day, with a floor price of $3.25 per MMBTU and a ceiling price of $4.60 per MMBTU. The net effect
of this fourth quarter 2001 hedge was a $.02 per Mcf increase in the average natural gas price for the year 2001. Of
the 50,000 MMBTU per day of costless collars, 25,000 MMBTU per day were terminated early, at a gain. As a result,
the Company recognized an additional $.70 per MMBTU on the 25,000 MMBTU of natural gas per day in 2001.
In addition to the hedging arrangements pertaining to the Company’s production as described above, NEMI employs
various derivative arrangements in connection with its purchases and sales of third-party production to lock in profits
or limit exposure to gas price risk. Most of the purchases made by NEMI are on an index basis; however, purchasers
in the markets in which NEMI sells often require fixed or NYMEX related pricing. NEMI may use a derivative to
convert the fixed or NYMEX sale to an index basis thereby determining the margin and minimizing the risk of price
volatility. During 2002, NEMI had derivative transactions with broker-dealers that ranged from 986,000 MMBTU to
2,085,000 MMBTU of natural gas per day. At December 31, 2002, NEMI had in place derivatives ranging from
approximately 20,000 MMBTU to 909,000 MMBTU of natural gas per day for January 2003 to May 2006 for future
physical transactions.
In 2001, NGM had derivative transactions with broker-dealers that ranged from 1,157,000 MMBTU to 1,388,000
MMBTU of natural gas per day. During 2000, NGM had derivative transactions with broker-dealers that ranged from
423,000 MMBTU to 1,023,000 MMBTU of natural gas per day. NEMI records derivative gains or losses relating to
fixed term sales as gathering, marketing and processing revenues in the periods in which the related contract is
completed.
Note 9 - Unconsolidated Subsidiary
Prior to January 2002, AMCCO was a 50 percent owned joint venture that owned an indirect 90 percent interest in
AMPCO, which completed construction of a methanol plant in Equatorial Guinea in the second quarter of 2001.
During 1999, AMCCO issued $125 million Series A-1 and $125 million Series A-2 senior secured notes due
December 15, 2004 to fund the remaining construction payments. On January 2, 2002, the Company’s partner in
AMCCO directed AMCCO to sell 50 percent of its interest in AMPCO as a component of the partner’s sale of its
Equatorial Guinea assets. The proceeds of the AMPCO sale were used to repay in full AMCCO’s $125 million Series
A-1 Notes on January 28, 2002 and to make a distribution to the Company’s partner. Since the Company’s partner in
AMCCO no longer retains an economic interest in AMPCO, the Company began consolidating AMCCO’s debt in
2002, thereby including the $125 million Series A-2 Notes in the Company’s balance sheet effective January 28, 2002.
The terms of the $125 million Series A-2 Notes remain unchanged.
The plant construction started during 1998 and initial production of commercial grade methanol commenced
May 2, 2001. The total construction costs of the plant and supporting facilities as of December 31, 2002 were $417
million, with the Company responsible for $208.5 million. The plant is designed to produce 2,500 MTpd of methanol,
which equates to approximately 20,000 Bpd. At this level of production, the plant would purchase approximately 125
MMcfpd from the 34 percent owned Alba field. The methanol plant has a 25-year contract to purchase natural gas
from the Alba field.
AMPCO, AMPCO Marketing LLC, AMPCO Services LLC and Samedan Methanol continue to be accounted for
using the equity method.
58
The following are summarized financial statements for subsidiaries accounted for using the equity method as of
December 31, 2002 and AMCCO as of December 31, 2001 and 2000:
Consolidated Balance Sheet (Unaudited)
Equity Method Subsidiaries
(in thousands)
Assets
Current assets
Non-current assets
Total Assets
Liabilities, Minority Interest and Members’ Equity
Current liabilities
Non-current liabilities
Minority interest
Members’ equity
Total Liabilities, Minority Interest and Members’ Equity
Consolidated Statement of Operations (Unaudited)
Equity Method Subsidiaries
(in thousands)
Revenue
Methanol sales
Other income
Total Revenue
Less cost of goods sold
Gross Margin
Expenses
DD&A
Other expenses
Interest (net of amount capitalized)
Administrative
Total Expenses
2002
2001
$ 74,832
412,134
$ 486,966
$ 37,419
449,547
$ 486,966
$ 86,213
432,431
$ 518,644
$ 14,892
272,406
41,210
190,136
$ 518,644
2002
2001
2000
$ 97,476
18,471
$ 115,947
71,687
$ 44,260
$ 20,763
3,076
$ 23,839
$ 43,343
5,346
$ 48,689
28,548
$ 20,141
$
8,427
4,363
19,069
317
$ 32,176
$
$
4,389
4,389
$
4,389
$
$
1,005
86
1,091
Net Income (Loss) Before Extraordinary Items
$ 20,421
$ (12,035)
$
3,298
Extraordinary Items (1)
$
$ 24,776
$
Net Income (Loss)
$ 20,421
$ (36,811)
$
3,298
(1) During the year, a prepayment penalty was recorded in connection with the early retirement of Series A-1
Secured Notes in 2002. The charge for the extraordinary item has been allocated to the Company’s partner in
AMCCO. Therefore, the Company has not recognized anything related to this loss in its financial statements.
59
Note 10 - Commitments and Contingencies
(a) The Company and its subsidiaries are involved in various legal proceedings in the ordinary course of
business. These proceedings are subject to the inherent uncertainties in any litigation. The Company is
defending itself vigorously in all such matters and does not believe that the ultimate disposition of such
proceedings will have a material adverse effect on the Company’s consolidated financial position, results of
operations or liquidity.
(b) On October 15, 2002, Noble Gas Marketing, Inc., Samedan Oil Corporation and Aspect Resources L.L.C.,
collectively referred to as the “Noble Defendants,” filed proofs of claim in the United States Bankruptcy
Court for the Southern District of New York in response to bankruptcy filings by Enron Corporation and
certain of its subsidiaries and affiliates, including Enron North America Corporation (“ENA”), under
Chapter 11 of the U.S. Bankruptcy Code. The proofs of claim relate to certain natural gas sales agreements
and aggregate approximately $18 million.
On December 13, 2002, ENA filed a complaint in which it objected to the Noble Defendants’ proofs of claim,
sought recovery of approximately $60 million from the Noble Defendants under the natural gas sales
agreements, sought declaratory relief in respect of the offset rights of the Noble Defendants and sought to
invalidate the arbitration provisions contained in certain of the agreements in issue. The Noble Defendants
intend to vigorously defend against ENA’s claims and do not believe that the ultimate disposition of the
bankruptcy proceeding will have a material adverse effect on the Company’s consolidated financial position,
results of operations or liquidity.
Note 11 - Geographical Data
The Company has operations throughout the world and manages its 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: United States, North Sea, Israel, Equatorial Guinea, and Other International, Corporate and Marketing.
Other International includes operations in Argentina, China, Ecuador and Vietnam.
Year Ended December 31, 2002
(Dollars in Thousands)
Consolidated
United States
North Sea Israel
Guinea
Equatorial
Other Int’l,
Corporate &
Marketing
$
298,000 $
402,602
152,575 $
382,946
72,041 $
19,497
$
45,830 $
3,052
27,554
(2,893 )
REVENUES
Oil Sales
Gas Sales
Gathering, Marketing and
Processing
Electricity Sales
Income from Unconsolidated
Subsidiaries
Other
Total Revenues
COSTS AND EXPENSES
Oil and Gas Operations
Transportation
Oil and Gas Exploration
Gathering, Marketing and
Processing
Electricity Generation
DD&A
SG&A
Interest Expense (net)
Total Costs and Expenses
714,091
18,257
9,532
1,246
1,443,728
133,826
16,441
150,701
703,556
15,946
285,286
47,664
47,709
1,401,129
100
535,621
389
91,927
(8 )
(8 )
110,849
120,695
241,113
27,768
500,425
10,812
9,618
5,210
28,279
630
54,549
9,532
58,414
9,848
1,341
2,625
31
10
5,849
2,045
2,666
19,083
714,091
18,257
765
757,774
2,317
6,823
20,830
703,556
15,946
10,014
17,211
47,709
824,406
INCOME (LOSS) BEFORE TAXES $
42,599 $
35,196 $
37,378 $
(2,674 ) $
39,331 $
(66,632 )
LONG-LIVED ASSETS
(PRIMARILY PROPERTY, PLANT
AND EQUIPMENT, NET)
60
As of December 31, 2002
$
2,139,784 $
1,225,501 $
89,316 $
180,267 $
154,231 $
490,469
61
Year Ended December 31, 2001
(Dollars in Thousands)
Consolidated
United States
North Sea Israel
Guinea
Equatorial
Other Int’l,
Corporate &
Marketing
$
260,908 $
610,904
155,289 $
587,483
39,972 $
22,850
$
38,841 $
2,201
26,806
(1,630 )
721,000
(5,075 )
953
1,588,690
133,549
16,012
152,096
708,292
284,016
44,164
25,951
1,364,080
(267 )
742,505
1,299
64,121
116,842
100,492
253,232
26,554
497,120
6,075
8,772
34,950
16,537
2,699
69,033
380
23
3
406
721,000
(262 )
745,914
3,857
7,240
16,235
708,292
10,335
13,991
25,951
785,901
(5,075 )
183
36,150
6,775
39
3,889
917
11,620
REVENUES
Oil Sales
Gas Sales
Gathering, Marketing and
Processing
Electricity Sales
Income (Loss) from
Unconsolidated Subsidiaries
Other
Total Revenues
COSTS AND EXPENSES
Oil and Gas Operations
Transportation
Oil and Gas Exploration
Gathering, Marketing and
Processing
Electricity Generation
DD&A
SG&A
Interest Expense (net)
Total Costs and Expenses
INCOME (LOSS) BEFORE TAXES $
224,610 $
245,385 $
(4,912 ) $
(406 ) $
24,530 $
(39,987 )
LONG-LIVED ASSETS
(PRIMARILY PROPERTY, PLANT
AND EQUIPMENT, NET)
As of December 31, 2001
$
1,953,211 $
1,308,504 $
103,781 $
101,407 $
87,461 $
352,058
Year Ended December 31, 2000
(Dollars in Thousands)
Consolidated
United States
North Sea Israel
Guinea
Equatorial
Other Int’l,
Corporate &
Marketing
$
235,658 $
564,936
165,299 $
539,868
16,964 $
24,392
$
25,501 $
235
27,894
441
589,933
1,489
7,441
1,399,457
121,866
9,241
84,868
574,266
230,800
47,291
31,642
1,099,974
1,144
706,311
273
41,629
107,431
80,367
207,690
36,781
432,269
5,256
6,072
1,396
12,297
2,049
27,070
581
581
589,933
6,024
624,292
4,854
3,169
2,462
574,266
9,452
7,354
31,642
633,199
1,489
27,225
4,325
62
1,361
1,107
6,855
REVENUES
Oil Sales
Gas Sales
Gathering, Marketing and
Processing
Electricity Sales
Income from Unconsolidated
Subsidiaries
Other
Total Revenues
COSTS AND EXPENSES
Oil and Gas Operations
Transportation
Oil and Gas Exploration
Gathering, Marketing and
Processing
Electricity Generation
DD&A
SG&A
Interest Expense (net)
Total Costs and Expenses
INCOME (LOSS) BEFORE TAXES $
299,483 $
274,042 $
14,559 $
(581 ) $
20,370 $
(8,907 )
LONG-LIVED ASSETS
(PRIMARILY PROPERTY, PLANT
AND EQUIPMENT, NET)
As of December 31, 2000
$
1,485,123 $
1,047,750 $
90,231 $
69,726 $
76,898 $
200,518
62
Note 12 - Company Stock Repurchase Forward Program
The Company’s Board of Directors, in February 2000, authorized a repurchase of up to $50 million in the Company’s
common stock. In the first quarter of 2000, the Company repurchased approximately $30 million of common stock.
The 2000 repurchase of 1,386,400 shares at an average cost of $21.84 per share was funded from the Company’s
current cash flow. On September 17, 2001 the Company’s Board of Directors approved an expansion of the original
repurchase program from $50 million to $100 million. During the fourth quarter of 2001, in conjunction with the
expanded repurchase program, the Board approved a stock repurchase forward program. Under the stock repurchase
forward program, one of the Company’s banks purchased approximately $35 million of the Company’s stock or
1,044,454 shares on the open market during the first quarter of 2002.
The program was scheduled to mature in January 2003 but has been extended to January 2004. Under the provisions
of the agreement with the bank, the Company can choose to either purchase the shares from the bank, issue additional
shares to the bank to the extent that the share price has decreased, pay the bank a net amount of cash to the extent that
the share price has decreased, or receive from the bank a net amount of cash to the extent that the share price has
increased. The bank has the right to terminate the agreement prior to the maturity date if the Company’s share price
decreases by 50 percent (to $16.77 per share) or if the Company’s credit rating is downgraded below BBB- (S&P) or
Baa3 (Moody’s). If either event occurs and the bank exercises its right to terminate, the Company still retains the right
to settle in cash or additional shares. The agreement limits the number of shares to be issued by the Company to
14,000,000 additional shares. Amounts paid or received related to the change in share price will be an addition or
reduction to the Company’s capital in excess of par value. No settlements have occurred to date. As of
December 31, 2002, the fair value of the Company’s obligation under the contract would be an obligation to pay
approximately $36.1 million to the bank (and hold the shares as treasury stock), or the bank would return 81,946
shares of Company stock to the Company, or the bank would pay $3.1 million to the Company.
63
Supplemental Oil and Gas Information
(Unaudited)
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, and estimates of engineers other than Noble Energy’s might differ
materially from the estimates set forth herein. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment. The procedures and methods used to
estimate approximately 80 percent of the Company’s proved reserves have been audited by a third party. This audit of
procedures and methods included all of the Company’s major international properties, whose reserves were also
estimated by third parties. 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. China, Ecuador and Equatorial Guinea are subject to production sharing contracts.
Proved Gas Reserves (Unaudited)
The following reserve schedule was developed by the Company’s reserve engineers and sets forth the changes in
estimated quantities of proved gas reserves of the Company during each of the three years presented.
Natural Gas and Casinghead Gas (MMcf)
Proved reserves as of:
January 1, 2002
Revisions of previous estimates
Extensions, discoveries and
other additions
Production
Sale of minerals in place
Purchase of minerals in place
December 31, 2002
Proved reserves as of:
January 1, 2001
Revisions of previous estimates
Extensions, discoveries and
other additions
Production
Sale of minerals in place
Purchase of minerals in place
December 31, 2001
Proved reserves as of:
January 1, 2000
Revisions of previous estimates
Extensions, discoveries and
other additions
Production
Sale of minerals in place
Purchase of minerals in place
December 31, 2000
United
States Argentina
4,348
(37)
751,283
(37,566)
Ecuador
Equatorial
Guinea
North
Sea
87,500 438,214 378,001 20,661
18
Israel
(245)
281
42,806
(119,664)
(20,290)
5,147
621,716
(424)
(2,788)
(12,549)
(6,201)
72,306
3,887
84,993 425,420 450,307 14,478
Total
1,680,007
(37,549 )
115,112
(141,626 )
(20,290 )
5,147
1,600,801
752,387
(46,886)
4,544
36
87,500 383,292 218,154 28,752
(1,583)
(2,550) 159,847
1,474,629
108,864
129,172
(134,507)
(246)
51,363
751,283
371
(603)
66,410
(8,938)
(6,508)
4,348
87,500 438,214 378,001 20,661
195,953
(150,556 )
(246 )
51,363
1,680,007
759,781
(7,022)
5,221
44
87,500 384,102
131
26,452
7,864
1,263,056
1,017
135,844
(136,010)
(4,840)
4,634
752,387
(721)
(941)
218,154
3,101
(8,665)
4,544
87,500 383,292 218,154 28,752
357,099
(146,337 )
(4,840 )
4,634
1,474,629
Proved developed gas reserves as of:
January 1, 2003
January 1, 2002
January 1, 2001
576,378
721,926
690,301
3,664
3,996
4,544
January 1, 2000
703,166
5,221
34,436 425,419
438,213
383,292
11,687
14,478
20,662
25,652
1,054,375
1,184,797
1,103,789
26,452
64
Proved Oil Reserves (Unaudited)
The following reserve schedule was developed by the Company’s reserve engineers and sets forth the changes in
estimated quantities of proved oil reserves of the Company during each of the three years presented.
Proved reserves as of:
January 1, 2002
Revisions of previous estimates
Extensions, discoveries and
other additions
Production
Sale of minerals in place
Purchase of minerals in place
December 31, 2002
Proved reserves as of:
January 1, 2001
Revisions of previous estimates
Extensions, discoveries and
other additions
Production
Sale of minerals in place
Purchase of minerals in place
December 31, 2001
Proved reserves as of:
January 1, 2000
Revisions of previous estimates
Extensions, discoveries and
other additions
Production
Sale of minerals in place
Purchase of minerals in place
December 31, 2000
Proved developed oil reserves as of:
January 1, 2003
January 1, 2002
January 1, 2001
January 1, 2000
United
States
71,672
(5,331)
2,929
(6,652)
(732)
137
62,023
69,700
324
7,453
(7,363)
(37)
1,595
71,672
65,523
(1,493)
12,788
(7,309)
(935)
1,126
69,700
52,847
64,534
58,903
60,618
Crude Oil and Condensate (Bbls in thousands)
North
Sea
11,114
(27)
Equatorial
Guinea
79,790
(34)
China
9,768
Argentina
10,277
36
(1,030)
1,162
33,182
(1,919)
(2,864)
9,283
10,930
111,019
8,223
Total
182,621
(5,356)
37,273
(12,465)
(732)
137
201,478
9,437
(6)
1,846
(1,000)
9,768
47,446
(272)
12,418
407
148,769
453
34,303
(1,687)
(1,711)
10,277
9,768
79,790
11,114
5,786
(366)
122,046
(1,606)
10,285
68
9,768
(916)
30,684
185
17,491
(914)
9,437
9,768
47,446
5,731
(654)
(229)
2,150
12,418
43,602
(11,761)
(37)
1,595
182,621
36,010
(9,793)
(1,164)
3,276
148,769
159,077
156,179
131,282
99,400
8,331
8,866
9,437
10,285
10,930
9,768
9,768
9,768
78,746
61,897
47,446
14,743
8,223
11,114
5,728
3,986
Proved Reserves. Proved reserves are estimated quantities of crude oil, natural gas, natural gas liquids and condensate
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.
Proved Developed Reserves. Proved developed reserves are proved reserves that are expected to be recovered through
existing wells with existing equipment and operating methods.
65
Oil and Gas Operations (Unaudited)
Aggregate results of operations for each period ended December 31, in connection with the Company’s crude oil and
natural gas producing activities, are shown below. Amounts are presented in accordance with SFAS No. 19 and may
not agree with amounts determined using traditional industry definitions.
(in thousands)
December 31, 2002
Revenues
Production costs
Exploration expenses
DD&A and valuation provision
Income (loss)
Income tax expense (benefit)
Result of operations from pro-
ducing activities (excluding
corporate overhead and interest
costs)
December 31, 2001
Revenues
Production costs
Exploration expenses
DD&A and valuation provision
Income (loss)
Income tax expense (benefit)
Result of operations from pro-
ducing activities (excluding
corporate overhead and interest
costs)
December 31, 2000
Revenues
Production costs
Exploration expenses
DD&A and valuation provision
Income (loss)
Income tax expense (benefit)
Result of operations from pro-
ducing activities (excluding
corporate overhead and interest
costs)
United
States
$ 535,697
142,578
102,323
258,310
32,486
11,705
Equatorial
Guinea
$ 45,830
8,840
1,341
5,835
29,814
13,825
Israel
$
10
1,725
909
(2,644)
North
Sea
$ 91,538
21,061
5,032
28,350
37,095
17,346
Other
Int’l
$ 27,537
13,093
20,733
9,606
(15,895)
666
Total
$ 700,602
185,582
131,154
303,010
80,856
43,542
$ 20,781
$ 15,989
$ (2,644)
$ 19,749
$ (16,561)
$ 37,314
$ 742,909
146,254
86,619
266,805
243,231
85,498
$ 38,841
5,381
39
3,830
29,591
14,429
$
3
5
382
(390)
$ 54,051
8,774
33,224
18,171
(6,118)
(2,721)
$ 19,999
7,675
17,021
8,679
(13,376)
(700)
$ 855,800
168,087
136,908
297,867
252,938
96,506
$ 157,733
$ 15,162
$
(390)
$
(3,397)
$ (12,676)
$ 156,432
$
$ 705,270
129,359
78,955
222,161
274,795
96,675
$ 25,501
5,010
121
1,355
19,015
8,978
581
(581)
$ 35,284
5,962
2,739
12,231
14,352
4,316
$ 25,298
6,952
2,169
8,292
7,885
5,033
$ 791,353
147,283
84,565
244,039
315,466
115,002
$ 178,120
$ 10,037
$
(581)
$ 10,036
$
2,852
$ 200,464
66
Costs Incurred in Oil and Gas Activities (Unaudited)
Costs incurred in connection with the Company’s crude oil and natural gas acquisition, exploration and development
activities for each of the years are shown below. Amounts are presented in accordance with SFAS No. 19 and may not
agree with amounts determined using traditional industry definitions.
(in thousands)
December 31, 2002
Property acquisition costs
Proved
Unproved
Total
Exploration costs
Development costs
December 31, 2001
Property acquisition costs
Proved
Unproved
Total
Exploration costs
Development costs
December 31, 2000
Property acquisition costs
Proved
Unproved
Total
Exploration costs
Development costs
United
States
Equatorial
Guinea
Israel
$
7,873
28,023
$ 35,896
$ 153,437
$ 131,244
$
$
$
1,351
$
$ 51,839
$
$ 1,725
$ 14,767
North
Sea
115
(238)
(123)
5,062
9,892
$
$
$
$
Other
Int’l
Total
$
2,730
$
2,730
$ 20,935
$ 60,934
$
7,988
30,515
$ 38,503
$ 182,510
$ 268,676
$ 91,251
76,808
$ 168,059
$ 134,247
$ 279,297
$
$
$
4,003
$
$ 10,364
$
131
$
$ 11,163
$
6,318
2,167
$
8,485
$ 34,766
$ 17,338
$
2,310
$
2,310
$ 19,233
$ 75,910
$ 97,569
81,285
$ 178,854
$ 192,380
$ 394,072
$
6,822
12,559
$ 19,381
$ 115,728
$ 180,339
$
$
62
$
$ 36,820
$ 50,861
1,927
$ 52,788
$ 11,387
$ 1,502
$ 41,284
2,218
$ 43,502
1,396
$
2,219
$
$
858
858
$
2,135
$
$ 44,648
$ 98,967
17,562
$ 116,529
$ 130,708
$ 265,528
Aggregate Capitalized Costs (Unaudited)
Aggregate capitalized costs relating to the Company’s crude oil and natural gas producing activities, and related
accumulated DD&A, as of December 31 are shown below:
(in thousands)
Unproved oil and gas properties $ 138,319 $
Proved oil and gas properties
U. S.
2002
Int’l
16,532
1,069,914
3,053,256
1,086,446
3,191,575
(1,972,282)
(189,540)
$ 1,219,293 $ 896,906
2001
Int’l
U. S.
Total
Total
$ 154,851 $ 142,232 $ 14,041 $ 156,273
3,765,642
3,921,915
(1,993,777)
$ 2,116,199 $ 1,294,637 $ 633,501 $ 1,928,138
3,007,757
3,149,989
(1,855,352)
4,123,170
4,278,021
(2,161,822)
757,885
771,926
(138,425)
Accumulated DD&A
Net capitalized costs
67
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
(Unaudited)
The following information is based on the Company’s best estimate of the required data for the Standardized Measure
of Discounted Future Net Cash Flows as of December 31, 2002, 2001 and 2000 in accordance with SFAS No. 69. The
Standard requires the use of a 10 percent discount rate. This information is not the fair market value nor does it
represent the expected present value of future cash flows of the Company’s proved oil and gas reserves.
December 31, 2002
(in millions of dollars)
Future cash inflows
Future production and
development costs
Future income tax expenses
Future net cash flows
10% annual discount for
United
States
Ecuador
Equatorial
Guinea
Israel
North
Sea
Other
Int’l
Total
$ 4,743
$ 268
$ 3,111
$1,181
$ 294
$ 648
$ 10,245
1,506
985
2,252
73
33
162
661
860
1,590
301
263
617
110
68
116
238
111
299
2,889
2,320
5,036
estimated timing of cash flows
877
59
953
301
21
93
2,304
Standardized measure of
discounted future net
cash flows
December 31, 2001
(in millions of dollars)
Future cash inflows
Future production and
development costs
Future income tax expenses
Future net cash flows
10% annual discount for
$ 1,375
$ 103
$ 637
$ 316
$ 95
$ 206
$ 2,732
$ 3,399
$ 264
$ 1,576
$ 900
$ 281
$ 317
$ 6,737
1,618
437
1,344
103
26
135
381
598
597
150
193
557
84
49
148
168
24
125
2,504
1,327
2,906
estimated timing of cash flows
562
56
406
364
25
65
1,478
Standardized measure of
discounted future net
cash flows
December 31, 2000
(in millions of dollars)
Future cash inflows
Future production and
development costs
Future income tax expenses
Future net cash flows
10% annual discount for
$ 782
$ 79
$ 191
$ 193
$ 123
$ 60
$ 1,428
$ 8,825
$ 305
$ 1,125
$ 524
$ 379
$ 462
$ 11,620
1,759
1,909
5,157
90
58
157
178
256
691
92
117
315
89
78
212
186
74
202
2,394
2,492
6,734
estimated timing of cash flows
2,037
62
273
124
84
80
2,660
Standardized measure of
discounted future net
cash flows
$ 3,120
$ 95
$ 418
$ 191
$ 128
$ 122
$ 4,074
The future net cash inflows for 2002, 2001 and 2000 do not include cash flows relating to the Company’s anticipated
future methanol or power sales.
68
Future cash inflows are computed by applying year-end prices (with a weighted average price of $29.48 per Bbl of
crude oil and $3.95 per Mcf of natural gas, after adjusting for 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 Company estimates that a $1.00 per Bbl change or a $.10 per Mcf change in the average crude oil price or the
average natural gas price, respectively, from the year-end price would change the discounted future net cash flows
before income taxes by approximately $105 million or $64 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 Company’s 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 income tax expenses are computed by applying the appropriate year-end statutory tax rates to the estimated
future pretax net cash flows relating to the Company’s proved crude oil and natural gas reserves, less the tax bases of
the properties involved. The future income tax expenses give effect to tax credits and allowances, but do not reflect
the impact of general and administrative costs and exploration expenses of ongoing operations relating to the
Company’s proved crude oil and natural gas reserves.
At December 31, 2002, the Company estimated natural gas imbalance receivables of $20.1 million and estimated
natural gas imbalance liabilities of $15.4 million; at year-end 2001, $20.9 million in receivables and $15.5 million in
liabilities; and at year-end 2000, $18.5 million in receivables and $14.2 million in liabilities. Neither the natural gas
imbalance receivables nor natural gas imbalance liabilities have been included in the standardized measure of
discounted future net cash flows as of each of the three years ended December 31, 2002, 2001 and 2000.
69
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 the
Company’s proved crude oil and natural gas reserves, as required by SFAS No. 69, at year-end are shown below.
(in millions)
Standardized measure of discounted
future net cash flows at the beginning
of the year
Extensions, discoveries and improved
recovery, less related costs
Revisions of previous quantity estimates
Changes in estimated future
development costs
Purchases (sales) of minerals in place
Net changes in prices and production costs
Accretion of discount
Sales of oil and gas produced, net of
production costs
Development costs incurred during
the period
Net change in income taxes
Change in timing of estimated future
production, and other
Standardized measure of discounted
future net cash flows at the end
of the year
2002
2001
2000
$ 1,428
$ 4,074
$ 1,493
486
(158)
(243)
(13)
1,636
208
448
114
(128)
108
(3,376)
564
1,462
(20)
(52)
69
2,448
185
(553)
(713)
(662)
254
(667)
220
908
172
(1,207)
354
(791)
186
$ 2,732
$ 1,428
$ 4,074
Supplemental Quarterly Financial Information (Unaudited)
Supplemental quarterly financial information for the years ended December 31, 2002 and 2001 is as follows:
(in thousands except per share amounts)
2002
Revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
2001
Revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
Mar. 31,
June 30,
Sept. 30,
Dec. 31,
Quarter Ended
$ 317,650
$ (15,098)
(.26)
$
(.26)
$
$ 330,292
$ 17,119
.30
$
.30
$
$ 339,666
(1,190 )
$
(.02)
$
(.02)
$
$ 456,120
$ 16,821
.29
$
.29
$
$ 564,206
$ 105,910
1.88
$
1.84
$
$ 417,698
$ 51,334
.91
$
.89
$
$ 308,673
3,808
$
.07
$
.07
$
$ 301,663
$ (27,476)
(.48)
$
(.48)
$
70
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
Effective May 14, 2002, the Board of Directors of Noble Energy, Inc., after careful consideration and based upon the
recommendation of its Audit Committee, dismissed its current independent public accountant, Arthur Andersen LLP.
This dismissal followed the decision by the Board of Directors to seek proposals from other independent auditors to
audit the Company’s consolidated financial statements for its fiscal year ended December 31, 2002.
Effective May 14, 2002, the Board of Directors, based on the recommendation of its Audit Committee, retained
KPMG LLP as its independent auditor with respect to the audit of the Company’s consolidated financial statements
for its fiscal year ended December 31, 2002.
During the Company’s two most recent fiscal years ended December 31, 2001, and during the subsequent interim
period preceding the replacement of Arthur Andersen LLP, there was no disagreement between the Company and
Arthur Andersen LLP on any matter of accounting principles or practices, financial statement disclosure, or auditing
scope or procedure that, if not resolved to Arthur Andersen LLP’s satisfaction, would have caused Arthur Andersen
LLP to make reference to the subject matter of the disagreement in connection with its report. The audit reports of
Arthur Andersen LLP on the consolidated financial statements of the Company as of and for the last two fiscal years
ended December 31, 2001 did not contain any adverse opinion or disclaimer of opinion, nor were these opinions
qualified or modified as to uncertainty, audit scope or accounting principles.
During the Company’s two most recent fiscal years ended December 31, 2001, and during the subsequent interim
period preceding the replacement of Arthur Andersen LLP, the Company had not consulted with KPMG LLP or other
independent auditors regarding the application of accounting principles to a specified transaction, either completed or
proposed, or the type of audit opinion that might be rendered on the Company’s financial statements.
Item 10.
Directors and Executive Officers of the Registrant.
PART III
The section entitled “Election of Directors” in the Registrant’s proxy statement for the 2003 annual meeting of
stockholders sets forth certain information with respect to the directors of the Registrant and is incorporated herein by
reference. Certain information with respect to the executive officers of the Registrant is set forth under the caption
“Executive Officers of the Registrant” in Part I of this report.
The section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” in the Registrant’s proxy statement
for the 2003 annual meeting of stockholders sets forth certain information with respect to compliance with
Section 16(a) of the Securities Exchange Act of 1934, as amended, and is incorporated herein by reference.
Item 11.
Executive Compensation.
The section entitled “Executive Compensation” in the Registrant’s proxy statement for the 2003 annual meeting of
stockholders sets forth certain information with respect to the compensation of management of the Registrant, and
except for the report of the Compensation, Benefits and Stock Option Committee of the Board of Directors and the
information therein under “Executive Compensation--Performance Graph” is incorporated herein by reference.
Item 12.
Security Ownership of Certain Beneficial Owners and Management.
The sections entitled “Security Ownership of Certain Beneficial Owners” and “Security Ownership of Directors and
Executive Officers” in the Registrant’s proxy statement for the 2003 annual meeting of stockholders set forth certain
information with respect to the ownership of the Registrant’s common stock and are incorporated herein by reference.
71
Item 13.
Certain Relationships and Related Transactions.
The section entitled “Certain Transactions” in the Registrant’s proxy statement for the 2003 annual meeting of
stockholders sets forth certain information with respect to certain relationships and related transactions, and is
incorporated herein by reference.
Item 14.
Controls and Procedures.
(a)
Evaluation of Disclosure Controls and Procedures. As of a date within 90 days prior to the filing of this
report, an evaluation of the effectiveness of the Company’s disclosure controls and procedures was
carried out under the supervision and with the participation of Charles D. Davidson, the Company’s
Chief Executive Officer, and James L. McElvany, the Company’s Chief Financial Officer. Based upon
that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s
disclosure controls and procedures were effective.
(b) Changes to Internal Controls. There were no significant changes to the Company’s internal controls or in
other factors that could significantly affect these controls subsequent to the date of their evaluation,
including any corrective actions with regard to significant deficiencies and material weaknesses.
Item 15.
Financial Statement Schedules, Exhibits and Reports on Form 8-K.
(a)
The following documents are filed as a part of this report:
(1) Financial Statements and Financial Statement Schedules and Supplementary Data: These documents
are listed in the Index to Consolidated Financial Statements in Item 8 hereof.
(2) Exhibits: The exhibits required to be filed by this Item 15 are set forth in the Index to Exhibits
accompanying this report.
(b)
The Registrant made no filings on Form 8-K during the quarter ended December 31, 2002.
72
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: March 11, 2003
NOBLE ENERGY, INC.
By: /s/ James L. McElvany
James L. McElvany,
Senior Vice President, Chief Financial Officer
and Treasurer
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/ James L. McElvany
James L. McElvany
/s/ Michael A. Cawley
Michael A. Cawley
/s/ Edward F. Cox
Edward F. Cox
/s/ James C. Day
James C. Day
/s/ Kirby L. Hedrick
Kirby L. Hedrick
/s/ Dale P. Jones
Dale P. Jones
/s/ Bruce A. Smith
Bruce A. Smith
Chairman of the Board, President,
Chief Executive Officer and Director
(Principal Executive Officer)
March 11, 2003
Senior Vice President,
Chief Financial Officer and Treasurer
(Principal Financial and Accounting
Officer)
March 11, 2003
March 11, 2003
March 11, 2003
March 11, 2003
March 11, 2003
March 11, 2003
March 11, 2003
Director
Director
Director
Director
Director
Director
73
I, Charles D. Davidson, certify that:
CERTIFICATION
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Noble Energy, Inc.;
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to
state a material fact necessary to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this annual report;
Based on my knowledge, the financial statements, and other financial information included in this annual
report, fairly present in all material respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) Designed such disclosure controls and procedures to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being prepared;
b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days
prior to the filing date of this annual report (the “Evaluation Date”); and
c) Presented in this annual report our conclusions about the effectiveness of the disclosure controls and
procedures based on our evaluation as of the Evaluation Date;
5.
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the
registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the
equivalent function):
a) All significant deficiencies in the design or operation of internal controls, which could adversely affect the
registrant’s ability to record, process, summarize and report financial data and have identified for the
registrant’s auditors any material weaknesses in internal controls; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant
role in the registrant’s internal controls; and
6.
The registrant’s other certifying officers and I have indicated in this annual report whether or not there were
significant changes in internal controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date:
March 11, 2003
/s/ CHARLES D. DAVIDSON
CHARLES D. DAVIDSON
Chief Executive Officer
74
I, James L. McElvany, certify that:
CERTIFICATION
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Noble Energy, Inc.;
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to
state a material fact necessary to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this annual report;
Based on my knowledge, the financial statements, and other financial information included in this annual
report, fairly present in all material respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) Designed such disclosure controls and procedures to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being prepared;
b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days
prior to the filing date of this annual report (the “Evaluation Date”); and
c) Presented in this annual report our conclusions about the effectiveness of the disclosure controls and
procedures based on our evaluation as of the Evaluation Date;
5.
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the
registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the
equivalent function):
a) All significant deficiencies in the design or operation of internal controls, which could adversely affect the
registrant’s ability to record, process, summarize and report financial data and have identified for the
registrant’s auditors any material weaknesses in internal controls; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant
role in the registrant’s internal controls; and
6.
The registrant’s other certifying officers and I have indicated in this annual report whether or not there were
significant changes in internal controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date:
March 11, 2003
/s/ JAMES L. McELVANY
JAMES L. McELVANY
Chief Financial Officer
75
Exhibit
Number
3.1
--
INDEX TO EXHIBITS
Exhibit **
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).
3.2
--
Certificate of Designations of Series A Junior Participating Preferred Stock of the Registrant dated
August 27, 1997 (filed 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).
3.3
--
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).
3.4
--
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).
4.1
--
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).
4.2
--
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).
4.3
--
4.4
--
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).
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).
4.5
--
Rights Agreement, dated as of August 27, 1997, between the Registrant and Liberty Bank and Trust
Company of Oklahoma City, N.A., as Right’s Agent (filed as Exhibit 4.1 to the Registrant’s
Registration Statement on Form 8-A filed on August 28, 1997 and incorporated herein by reference).
4.6
--
10.1 * --
Amendment No. 1 to Rights Agreement dated as of December 8, 1998, between the Registrant and
Bank One Trust Company, as successor Rights Agent to Liberty Bank and Trust Company of
Oklahoma City, N.A. (filed as Exhibit 4.2 to the Registrant’s Registration Statement on Form 8-A/A
(Amendment No. 1) filed on December 14, 1998 and incorporated herein by reference).
Restoration of Retirement Income Plan for Certain Participants in the Noble Affiliates 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 herewith.
76
Exhibit
Number
Exhibit **
10.3 * --
Noble Energy, Inc. Restoration Trust effective August 1, 2002, filed herewith.
10.4 * --
Noble Affiliates, Inc. Deferred Compensation Plan (formerly known as the Noble Affiliates Thrift
Restoration Plan dated May 9, 1994) as restated effective August 1, 2001, filed herewith.
10.5 * --
Noble Affiliates, Inc. 1992 Stock Option and Restricted Stock Plan, as amended, dated
January 27, 2003, filed herewith.
10.6 * --
1982 Stock Option Plan of the Registrant (filed as Exhibit 4.1 to the Registrant’s Registration
Statement on Form S-8 (Registration No. 2-81590) and incorporated herein by reference).
10.7 * --
Amendment No. 1 to the 1982 Stock Option Plan of the Registrant (filed as Exhibit 4.2 to the
Registrant’s Registration Statement on Form S-8 (Registration No. 2-81590) and incorporated herein
by reference).
10.8 * --
Amendment No. 2 to the 1982 Stock Option Plan of the Registrant (filed as Exhibit 10.11 to the
Registrant’s Annual Report on Form 10-K for the year ended December 31, 1995 and incorporated
herein by reference).
10.9 * --
1988 Nonqualified Stock Option Plan for Non-Employee Directors of the Registrant, as amended and
restated, effective as of April 23, 2002 (filed as Exhibit 10.2 to the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended March 31, 2002 and incorporated herein by reference).
10.10* --
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).
10.11* --
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).
10.12 --
10.13 --
10.14 --
10.15* --
Guaranty of the Registrant dated October 28, 1982, guaranteeing certain obligations of Samedan (filed
as Exhibit 10.12
the year ended
December 31, 1993 and incorporated herein by reference).
the Registrant’s Annual Report on Form 10-K for
to
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).
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).
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).
77
Exhibit
Number
10.16* --
10.17 --
10.18 --
Exhibit **
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 10.18 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2001
and incorporated herein by reference).
Five-year Credit Agreement dated as of November 30, 2001 among the Registrant, as borrower,
JPMorgan Chase Bank, as the administrative agent for the lenders, Societe Generale, as the
syndication agent for the lenders, Mizuho Financial Group, Credit Lyonnais, New York Branch, The
Royal Bank of Scotland PLC, and Deutsche Bank Ag New York Branch, 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, 2001 and incorporated herein by
reference).
364-day Credit Agreement dated as of November 30, 2001 among the Registrant, as borrower,
JPMorgan Chase Bank, as the administrative agent for the lenders, Societe Generale, as the
syndication agent for the lenders, Mizuho Financial Group, Credit Lyonnais, New York Branch, The
Royal Bank of Scotland PLC, and Deutsche Bank Ag New York Branch, 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, 2001 and incorporated herein by
reference).
10.19 --
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 herewith.
21
--
Subsidiaries, filed herewith
23
--
Consent of KPMG LLP, filed herewith
99.1
--
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)
99.2
--
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)
* 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, Chief Financial Officer and Treasurer, Noble Energy, Inc., 350 Glenborough
Drive, Suite 100, Houston, Texas 77067.
78