FORM 10−K
NOBLE ENERGY INC − NBL
Filed: March 15, 2004 (period: December 31, 2003)
Annual report which provides a comprehensive overview of the company for the past year
Table of Contents
PART I
Item 1. Business.
Item 2. Properties.
Item 3. Legal Proceedings.
Item 4. Submission of Matters to a Vote of Security Holders.
PART II
Item 5. Market for Registrant s Common Equity, Related Stockholder Matters and
Item 6. Selected Financial Data.
Item 7. Management s Discussion and Analysis of Financial Condition and Results of
Operations.
Item 7a. Quantitative and Qualitative Disclosures About Market Risk.
Item 8. Financial Statements and Supplementary Data.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure.
Item 9a. Controls and Procedures.
PART III
Item 10. Directors and Executive Officers of the Registrant.
Item 11. Executive Compensation.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matt
Item 13. Certain Relationships and Related Transactions.
Item 14. Principal Accountant Fees and Services.
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8−K.
SIGNATURES
INDEX TO EXHIBITS
EX−10.20 (Material contracts)
EX−12.1 (Statement regarding computation of ratios)
EX−21 (Subsidiaries of the registrant)
EX−23.1 (Consents of experts and counsel)
EX−23.2 (Consents of experts and counsel)
EX−31.1
EX−31.2
EX−32.1
EX−32.2
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10−K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2003
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)
100 Glenborough Drive, Suite 100
Houston, Texas
(Address of principal executive offices)
77067
(Zip Code)
(Registrant’s telephone number, including area code)
(281) 872−3100
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
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S−K is not contained herein, and will not
be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part
III of this Form 10−K or any amendment to this Form 10−K.
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b−2 of the Act). Yes
No
Aggregate market value of Common Stock held by nonaffiliates as of June 30, 2003: $2,085,000,000.
Number of shares of Common Stock outstanding as of March 1, 2004: 57,710,547.
DOCUMENT INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2004 Annual Meeting of Stockholders to be held on April 27, 2004,
which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2003, 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
Dispositions of Oil and Gas Properties
Marketing
Regulations and Risks
Competition
Unconsolidated Subsidiaries
Geographical Data
Employees
Available Information
Item 2.
Properties
Offices
Crude Oil and Natural Gas
Item 3.
Legal Proceedings
Item 4.
Submission of Matters to a Vote of Security Holders
Executive Officers of the Registrant
PART II.
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities
Item 6.
Selected Financial Data
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7a.
Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Financial Statements and Supplementary Data
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9a.
Controls and Procedures
PART III.
Item 10.
Directors and Executive Officers of the Registrant
Item 11.
Executive Compensation
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
Item 13.
Certain Relationships and Related Transactions
Item 14.
Principal Accountant Fees and Services
Item 15.
Exhibits, Financial Statement Schedules and Reports on Form 8−K
PART IV.
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”), formerly known as Noble Affiliates, Inc., is a Delaware corporation that has
been publicly traded on the New York Stock Exchange since 1980. Noble Energy has been engaged, directly or through its
subsidiaries, in the exploration, production and marketing of crude oil and natural gas since 1932, when Noble Energy’s predecessor,
Samedan Oil Corporation (“Samedan”), was organized. Noble Energy was organized in 1969 under the name “Noble Affiliates, Inc.”
and was Samedan’s parent entity until Samedan was merged into Noble Energy at year−end 2002. 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.
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:
Bbl
Bbls
MBbls
Bpd
Bopd
MMBbl
MBpd
MMBpd
MBopd
MMBopd
BOE
MMBoe
MMBoepd
$MM
Kwh
MW
MWH
Mcf
Mcfpd
Mcfe
MMcf
MMcfepd
MMcfpd
Bcf
Bcfe
Bcfepd
Bcfpd
BTU
BTUpcf
MMBTU
MMBTUpd Million British thermal unit per day
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
Million barrels oil per day
Barrels oil equivalent
Million barrels oil equivalent
Million barrels oil equivalent per day
Millions of dollars
Kilowatt hour
Megawatt
Megawatt hours
Thousand cubic feet
Thousand cubic feet per day
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
British thermal unit
British thermal unit per cubic foot
Million British thermal unit
MTpd
LPG
Metric tons per day
Liquefied petroleum gas
For reporting BOE or Mcfe, one Bbl of oil, condensate or LPG is equal to six Mcf of natural gas.
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. 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 and
Texas); the Mid−Continent Region (Oklahoma and Kansas); and the Rocky Mountain Region (Colorado, Montana, Nevada, Wyoming
and California). The international areas of operations include Argentina, China, Ecuador, Equatorial Guinea, the Mediterranean Sea
(Israel), the North Sea (Denmark, the Netherlands and the 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 larger prospect sizes and potential higher rates of return. The Company’s
current offshore production is derived from 186 gross wells operated by Noble Energy and 299 gross wells operated by others. At
December 31, 2003, the Company held offshore federal leases covering 932,820 gross developed acres and 755,658 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 and Texas. The Mid−Continent Region
covers Oklahoma and Kansas. Properties in the Rocky Mountain Region are located in Colorado, Montana, Nevada, Wyoming and
California.
Noble Energy’s current onshore production is derived from 1,330 gross wells operated by the Company and 511 gross wells operated
by others. At December 31, 2003, the Company held 667,708 gross developed acres and 351,201 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, 2003, the Company
held 28,988 gross developed acres and 2,426,221 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 a concession offshore China in the southern portion of Bohai Bay. At December 31, 2003, the
Company held 7,413 gross developed acres and 1,617,549 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.
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
2
(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. With a current generating capacity of 130 MW of electricity, additional capital investment for
combined cycle to the power plant could ultimately increase capacity to generate 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. 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 contract through 2026 to purchase natural gas from the Alba field. The plant is owned by Atlantic
Methanol Production Company LLC (“AMPCO”), in which the Company 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
Subsidiaries” of this Form 10−K.
At December 31, 2003, 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 three licenses and two leases. At
December 31, 2003, the Company held 123,552 gross developed acres and 292,572 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 December 24, 2003,
the commencement of production of natural gas from its Mari−B field. Sales of natural gas to Israel Electric Corporation (“IEC”)
began in February 2004 under a definitive agreement executed in June 2002. 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, the Netherlands and the United Kingdom) since 1996. At December 31, 2003, the Company
held 66,354 gross developed acres and 573,838 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. In December 2003, Noble Energy elected not to pursue any additional exploration efforts in the Nam Con Son Basin of
Vietnam. As a result, the Company wrote off its investment in Vietnam and is in the process of assigning its ownership in the two
blocks. During 2003, the Company expensed one exploratory well and associated exploration costs.
Production Activities
Revenues from sales of crude oil, natural gas and gathering, marketing and processing (“GMP”) have accounted for approximately 90
percent or more of consolidated revenues for each of the last three fiscal years.
3
Operated Property Statistics. The percentage of properties operated by the Company indicates the amount of control over timing of
operations. The percentage of operated crude oil and natural gas wells on both the well count and percentage of sales volume basis are
shown in the following table as of December 31:
(in percentages)
Operated well count basis
Operated sales volume basis
2003
2002
2001
Oil
Gas
Oil
Gas
Oil
Gas
19.6
33.3
60.1
48.8
23.3
29.3
62.8
45.1
24.8
37.2
60.6
52.3
Non−operated Property Statistics. The percentage of non−operated crude oil and natural gas wells on both the well count and the
percentage of sales volume basis are shown in the following table as of December 31:
(in percentages)
Non−operated well count basis
Non−operated sales volume basis
2003
2002
2001
Oil
Gas
Oil
Gas
Oil
Gas
80.4
66.7
39.9
51.2
76.7
70.7
37.2
54.9
75.2
62.8
39.4
47.7
Net Production. The following table sets forth Noble Energy’s net crude oil and natural gas production, including royalty, from
continuing operations, for the three years ended December 31:
Crude oil production (MMBbl)
Natural gas production (Bcf)
2003
2002
2001
13.1
122.9
10.6
124.5
9.1
129.8
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, including royalty, from continuing operations, for the three years ended December 31:
Total crude oil equivalents (MMBoe)
Total natural gas equivalents (Bcfe)
2003
2002
2001
33.6
201.7
31.4
188.2
30.8
184.5
Acquisitions of Oil and Gas Properties, Leases and Concessions
During 2003, Noble Energy spent approximately $1.2 million on the purchase of proved crude oil and natural gas properties. The
Company spent approximately $8.0 million in 2002 and $97.6 million in 2001 on the acquisition of proved properties. For more
information, see “Item 2. Properties—Crude Oil and Natural Gas” of this Form 10−K.
During 2003, Noble Energy spent approximately $10.2 million on acquisitions of unproved properties. The Company spent
approximately $30.6 million in 2002 and $81.3 million in 2001 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.
Dispositions of Oil and Gas Properties
During 2003, the Company identified five packages of non−core domestic properties to be sold. The properties held for disposition
were reported as discontinued operations. Overall, these properties represented approximately six percent of year−end reserves and
nine percent of 2003 production. Four of the five packages closed in 2003; the fifth
4
is scheduled to close in the first half of 2004. The Company received $79.9 million from the sale of the four packages. The estimated
reserves associated with these four packages were 17.2 MMBoe.
During 2002, the Company sold approximately 4.1 MMBoe of reserves and received approximately $20.4 million from the sale of
properties.
Marketing
NEMI seeks opportunities to enhance the value of the Company’s domestic natural gas production by marketing directly to end−users
and aggregating natural gas to be sold to natural gas marketers and pipelines. During 2003, approximately 86 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 production 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 contract does not specify scheduled quantities or delivery points and expires on May 31, 2004. The Company sold
approximately 64 percent of its natural gas production to NEMI in 2003. NEMI’s revenues from sales of natural gas, including related
derivative financial transactions, less cost of goods sold are reported in GMP. 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
approximately four percent of its 2003 natural gas sales.
Substantial competition in the natural gas marketplace continued in 2003. The Company’s average natural gas price increased $1.24
from $2.89 per Mcf in 2002 to $4.13 per Mcf in 2003. Due to the volatility of natural gas prices, the Company, from time to time, has
used derivative instruments and may do so in the future as a means of controlling its exposure to commodity 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.
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 34 percent of the Company’s crude oil production as well as certain third−party crude oil. The Company records all of
NEMI’s revenues from sales of crude oil, less cost of goods sold, as GMP. All intercompany sales and expenses are eliminated in the
Company’s consolidated financial statements.
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 from continuing operations increased $3.50 from $24.22 per Bbl in 2002 to $27.72 per Bbl in 2003. Due to the volatility of crude
oil prices, the Company, from time to time, has used derivative 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 2003 accounted for approximately 16 percent of
the Company’s crude oil sales, representing approximately six percent of total revenues. The five largest purchasers accounted for
approximately 57 percent of total crude oil sales. The largest single non−affiliated purchaser of the Company’s natural gas production
in 2003 accounted for approximately five percent of its natural gas sales, representing approximately three percent of total revenues.
The five largest purchasers accounted
5
for approximately 18 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 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 such a release or discharge, subject to certain specified limitations on liability, may be 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 hazardous substances that have 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
6
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, 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 that include, in various degrees,
directors and officers liability, general liability, well control, pollution, terrorism acts 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 desirable exploratory and producing
properties. 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 Subsidiaries
Through its ownership in AMCCO, the Company owns a 45 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−2 senior secured notes
due December 15, 2004 to fund construction payments owed in connection with the construction of the methanol plant. The
Company’s investment in the methanol plant is included in investment in unconsolidated subsidiaries. The $125 million Series A−2
notes are in current installments of long−term debt on the Company’s balance sheet.
7
The plant construction started during 1998, and initial production of commercial grade methanol commenced May 2, 2001. 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 of natural gas from the 34 percent−owned Alba field. The methanol plant has a contract
through 2026 to purchase natural gas from the Alba field. For more information, see “Item 8. Financial Statements and Supplementary
Data—Note 9 − Unconsolidated Subsidiaries” 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 crude oil and natural gas exploration, exploitation and production: United States,
North Sea, Israel, Equatorial Guinea, and Other International, Corporate and Marketing. 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 decreased during the year from 624 at December 31, 2002, to 583 at
December 31, 2003. In addition, one hundred sixty−seven foreign nationals worked in Noble Energy offices in China, Ecuador, Israel,
the United Kingdom and Vietnam as of December 31, 2003.
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, Forms 3, 4 and 5 filed on behalf of directors and officers and amendments to those reports as soon as reasonably
practicable after such materials are electronically filed with or furnished to the United States Securities and Exchange Commission
(“SEC”).
Also posted on the Company’s website, and available in print upon request of any stockholder to the Investor Relations Department,
are charters for the Company’s Audit Committee, Compensation, Benefits and Stock Option Committee, Corporate Governance and
Nominating Committee and the Environmental, Health and Safety Committee. Copies of the Code of Business Conduct and Ethics
and the Code of Ethics for Chief Executive and Senior Financial Officers governing our directors, officers and employees (the
“Codes”) are also posted on the Company’s website under the “Corporate Governance” section. Within the time period required by the
SEC and the New York Stock Exchange, Inc., the Company will post on its website any modifications to the Codes and any waivers
applicable to senior officers as defined in the applicable Code, as required by the Sarbanes−Oxley Act of 2002.
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, information systems and related administrative functions.
Crude Oil and Natural Gas
The Company 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
8
exploratory drilling, where appropriate, on properties for which it acquired exploration rights. During 2003, Noble Energy drilled or
participated in the drilling of 164 gross (66.6 net) wells, comprised of 64 gross (10.1 net) international wells and 100 gross (56.5 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. During 2003, Noble Energy’s offshore drilling program included 20 gross (6.1 net) exploration and development
wells. Of the wells drilled in 2003, 14 wells, or 70 percent, were commercial discoveries and six wells were dry holes.
Green Canyon 136 A−8 (Shasta) commenced production in January 2003 at 30 MMcfpd gross. Noble Energy has a 25 percent
working interest in Shasta. The reserves on this previously existing field were recorded in prior years.
Green Canyon 199 (Lorien), an apparent deepwater crude oil discovery in 2003, is located in 2,177 feet of water and was drilled to a
total depth of 17,432 feet. The well encountered over 120 feet of oil in a high−quality reservoir interval. Further appraisal will be
conducted in 2004. The Company did not record any discovery of reserves on this property in 2003. The Company has a 20 percent
working interest in Lorien.
Green Canyon 282 (Boris), a deepwater crude oil discovery, commenced production from the second well in the third quarter of 2003
at an initial gross rate of 4,000 Bopd and 7 MMcfpd. Combined with the discovery well, the field’s gross production was 20,000 Bopd
and 33 MMcfpd at January 1, 2004. The Company has a 25 percent working interest in Boris. The reserves on this property were
recorded in 2001 and 2002 without a flow test but did utilize other testing procedures.
Mississippi Canyon 837 (Loon), a deepwater natural gas discovery in 2001, is scheduled to commence production in the second
quarter of 2004. The estimated initial gross production rate is 12 MMcfpd. Noble Energy has a 40 percent working interest in Loon.
The reserves on this property were recorded in 2001 after a flow test of the well.
Noble Energy had several significant deep shelf properties commence production in 2003. State Lease 340 A−1 (Mound Point), a
natural gas discovery in which the Company has a 25 percent working interest, commenced production in the fourth quarter at a gross
rate of 850 Bopd and 28 MMcfpd. Viosca Knoll 251 A−3 and A−4 commenced production in the second quarter at a combined gross
rate of 26 MMcfpd. Noble Energy has a 40 percent working interest in these wells. South Timbalier 316 (Roaring Fork) commenced
production in the third quarter from the discovery well at an initial gross rate of 6,000 Bopd and 13 MMcfpd. During February 2004,
the field’s gross production was 19,600 Bopd and 40 MMcfpd. The Company has a 40 percent working interest in Roaring Fork.
During 2003, the Company expensed four exploratory wells related to its offshore activity.
Noble Energy was the successful bidder, alone or with partners, on five of seven blocks at the Central Gulf of Mexico Outer
Continental Shelf Sale 185. Of the five approved bids, two were on blocks in deepwater, one on a block in the deep shelf and the
remaining blocks were on the conventional shelf. Approved bids totaled approximately $2.9 million net to the Company’s interest.
Noble Energy will be the designated operator on all five of the approved bids.
The Company also participated in the Western Gulf of Mexico Outer Continental Shelf Sale 187. Noble Energy was the successful
bidder, alone or with partners, on five of seven blocks. Of the five approved bids, three were on blocks in deepwater and the remaining
blocks were on the conventional shelf. Approved bids totaled approximately $2.3 million net to the Company’s interest. Noble Energy
will be the designated operator on all five of the approved bids.
9
Domestic Onshore. During 2003, Noble Energy’s onshore drilling program included 80 gross (50.4 net) exploration and development
wells. Of the wells drilled in 2003, 50 wells, or 63 percent, were commercial discoveries and 30 wells were dry holes.
The Gulf Coast remains one of Noble Energy’s most active areas. During 2003, the Company drilled 45 wells in the Gulf Coast with a
53 percent success rate. The Aspect Resources joint venture accounted for a substantial portion of Noble Energy’s drilling activity
during 2003 with 26 wells drilled and 13 successes.
Noble Energy had a three well program on its Wildcat Ridge project, located in Jefferson County, Texas. Two of the three wells
drilled were successful, and additional prospects will be drilled in 2004. The two successful wells were producing 771 BOE per day,
gross, at year−end 2003. The Company has a 37.5 percent working interest in the Wildcat Ridge project.
In south Louisiana, Noble Energy drilled and completed a discovery well and successful offset on the Savanne D’Or prospect in
Lafourche Parish. The wells were producing 2,400 BOE per day, gross, at year−end 2003. The Company owns a 40 percent working
interest in the prospect.
In Duval County, Texas, Noble Energy drilled six wells, of which five were successful. The prospects were identified with proprietary
3D seismic acquired in late 2002. The five successful wells were producing 2,100 BOE per day, gross, at year−end 2003. Noble
Energy’s working interests in the wells drilled in 2003 range from 85 percent to 100 percent.
During 2003, the Company expensed 22 exploratory wells related to its onshore activity.
Argentina. Noble Energy participated with a 13 percent working interest in 55 development wells in the El Tordillo field during 2003.
The Company has been awarded and is awaiting final government approval on a crude oil and natural gas exploration permit of
approximately 1.2 million acres. The permit is located adjacent to an existing permit in the Cuyo Basin of Mendoza Province in
western Argentina.
China. Noble Energy has a 57 percent working interest in the Cheng Dao Xi (“CDX”) field, which is located on the south side of
Bohai Bay off the coast of China. Initial production from CDX commenced on January 13, 2003. During 2003, CDX averaged 5,781
Bopd (3,295 Bopd net to Noble Energy).
During 2003, the Company expensed two exploratory wells related to its block 16/02 activity in China. The 16/02 block was
subsequently relinquished during the year. Noble Energy also relinquished its acreage in the Cheng Zi Kou field during 2003.
Ecuador. In September 2002, Noble Energy commenced operations of its 100 percent−owned integrated gas−to−power project. The
project includes the Amistad field, which is located in the shallow waters of the Gulf of Guayaquil near the coast of Ecuador. The
power plant is located on the coast near Machala, Ecuador and connects to the Amistad field via a 40−mile pipeline. The Machala
power plant is the only natural gas−fired commercial power generator in Ecuador and currently has a generating capacity of 130 MW
of electricity from twin General Electric Frame 6Fa turbines. Additional development drilling is planned for 2004.
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. The Phase 2A project includes adding two platforms, 12 wells, three pipelines and
two compressors. The processed dry gas is then re−injected into the reservoir.
Initial startup of Phase 2A began in November 2003. The Phase 2A expansion is expected to increase gross condensate production
approximately 27,700 Bpd (8,400 Bpd net to Noble Energy).
10
Phase 2B, scheduled to be completed late in 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 Bpd (1,800 Bpd
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 ramp−up of Phase 2A in 2004 and the completion of Phase 2B, gross condensate and LPG capacity will be
approximately 52,000 Bpd (15,800 Bpd net to Noble Energy) and 16,700 Bpd (4,700 Bpd net to Noble Energy), respectively.
Noble Energy, through its subsidiaries, 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. The
AMPCO plant purchases and processes approximately 125 MMcfpd of natural gas into 2,500 MTpd of methanol.
Israel. The Company and its partners have an 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. Sales commenced
February 18, 2004. Noble Energy has a 47 percent working interest in the project.
North Sea. The Company continued to focus on production and exploration growth in 2003 and added reserves in producing fields.
The Company participated in two non−operated discoveries in the North Sea. Both discoveries are expected to lead to development.
The Company plans to drill one exploration well in 2004.
Vietnam. In December 2003, Noble Energy elected not to pursue any additional exploration efforts in the Nam Con Son Basin of
Vietnam. As a result, the Company wrote off its investment in Vietnam and is in the process of assigning its ownership in the two
blocks. During 2003, the Company expensed one exploratory well and associated exploration costs.
11
Net Exploratory and Development 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.
Year Ended
December 31,
2003
2002
2001
Net Exploratory Wells
Productive(1)
Dry(2)
Net Development Wells
Productive(1)
Dry(2)
U.S.
Int’l
10.84
9.78
4.87
.07
.63
U.S.
12.40
11.45
10.79
Int’l
U.S.
2.67
3.27
5.41
25.10
41.53
68.30
Int’l
7.32
12.84
13.67
U.S.
8.16
11.17
12.88
Int’l
1.62
(1)
A productive well is an exploratory or a development well that is not a dry hole.
A dry hole is an exploratory or development well determined to be incapable of producing either crude oil or natural gas in
(2)
sufficient quantities to justify completion as an oil or gas well.
At January 31, 2004, Noble Energy was drilling 9 gross (4.1 net) exploratory wells and 3 gross (.4 net) development wells. These
wells are located onshore in California, Louisiana, Nevada, Texas and Argentina and offshore in the Gulf of Mexico. These wells have
objectives ranging from approximately 4,500 feet to 21,500 feet. The drilling cost to Noble Energy of these wells will be
approximately $20.5 million if all are dry and approximately $43.8 million if all are completed as producing wells.
12
Crude Oil and Natural Gas Wells. Due to the various asset dispositions in 2003, there was a significant decrease from 2002 in the
number of gross wells in which Noble Energy held an interest. 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
2003(1)(2)
2002(1)(2)
2001(1)(2)
Gross
Net
Gross
Net
Gross
Net
196.0
186.0
716.0
1,098.0
1,645.0
299.0
34.0
1,978.0
118.2
114.2
88.8
321.2
1,042.1
116.5
8.4
1,167.0
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
Productive wells are producing wells and wells capable of production. A gross well is a well in which a working interest is
(1)
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
2003
2002
2001
Gross
Net
Gross
Net
Gross
Net
9.0
29.0
573.0
337.0
5.8
11.3
109.2
142.5
12.0
28.5
565.0
121.0
6.0
8.9
212.3
73.0
13.5
36.5
391.0
100.0
6.9
14.0
179.2
36.3
At year−end 2003, Noble Energy had less than nine 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, 2003, 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.
The SEC requested clarification, which the Company provided, as to the Company’s Israel and Equatorial Guinea gas reserves
recorded in excess of existing contract amounts. SEC guidelines do not limit reserve bookings only to contracted volumes if it can be
demonstrated that there is reasonable certainty that a market exists, which the Company believes exists in both of these situations. The
Israel gas contract is for a period of 11 years. The Israel gas market, as estimated by the Israeli Ministry of National Infrastructure,
from 2005 to 2020, is twenty times greater than Noble Energy’s
13
uncontracted net estimated proved reserves. In Equatorial Guinea, the gas contract, which runs through 2026, is between the field
owners and the methanol plant owners. Noble Energy, through its subsidiaries, holds a working interest in the field as well as an
interest in the methanol plant. The Company has recorded reserves through the end of the concession’s term in 2040. Noble Energy
has obtained independent third−party engineer reserve estimates for both of these projects.
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 from continuing operations.
Average sales price per Bbl of crude oil (1):
United States
International
Combined (2)
Average sales price per Mcf of natural gas (1):
United States
International (3)
Combined (4)
Average production cost per Mcfe (5):
United States
International
Combined
2003
Year Ended December 31,
2002(6)
2001(6)
$
$
$
$
$
$
$
$
$
26.21
28.94
27.72
4.75
1.17
4.13
.74
.78
.75
$
$
$
$
$
$
$
$
$
23.29
24.98
24.22
3.24
1.18
2.89
.63
.43
.57
$
$
$
$
$
$
$
$
$
23.02
23.98
23.49
4.21
1.60
3.86
.61
.39
.56
(1)
Net production amounts used in this calculation include royalties.
(2) Reflects a reduction of $1.01 per Bbl in 2003, $.02 per Bbl in 2002 and an increase of $.01 per Bbl in 2001 from hedging in the
United States.
(3) Ecuador natural gas revenues and natural gas production volumes are excluded in the calculation of the International average
sales price per Mcf of natural gas. The gas−to−power project in Ecuador is 100 percent owned by Noble Energy. Intercompany natural
gas sales are eliminated for accounting purposes.
(4) Reflects a reduction of $.44 per Mcf in 2003, an increase of $.05 per Mcf in 2002 and $.04 per Mcf in 2001 from hedging in the
United States.
(5) Production costs include lease operating expense, workover expense, production taxes and other related lifting costs. The natural
gas production volumes associated with the Company’s gas−to−power project in Ecuador for 2003 and 2002 were 7,842 MMcf and
2,788 MMcf, respectively, and are excluded in the average production cost per Mcfe for both International and Combined.
(6) Reclassified from prior years due to discontinued operations.
14
Significant Offshore Undeveloped Lease Holdings (interests rounded to nearest whole percent)
Block
East Breaks
279*
464*
465*
475*
510*
519*
563*
Green Canyon
23
85*
142
185*
186*
187*
199*
228*
303*
507*
723*
724*
768*
955*
958*
West Cameron
136
311
392
393
400
419
422
Working
Interest (%)
33
48
48
100
33
100
100
100
50
100
100
100
100
20
100
40
50
100
100
100
7
25
40
10
100
100
100
100
50
423
438
443
446
Mustang Island
829
830
831
Vermilion
208
227
228
230
232
235
352
353
391
Garden Banks
25
416*
460*
461*
751*
795*
841*
Main Pass
107
109
110
192
East Cameron
342
348
355
South Timbalier
62
278
Ship Shoal
73
Galveston
249−L
South Marsh Island
38
64
70
145
195
Mississippi Canyon
26*
70*
71*
115*
116*
123*
159*
204*
524*
100
100
100
100
80
80
100
25
100
100
100
50
100
100
100
100
50
100
100
100
100
100
39
25
25
25
100
67
30
100
100
50
50
50
100
67
50
100
50
75
75
75
75
100
75
75
100
50
595*
602*
639*
665*
769*
811*
849*
855*
856*
857*
892*
896*
900*
901*
911*
999*
1000*
Brazos
308−L
543
Ewing Bank
834
949
993
Eugene Island
35
36
37
38
96
317
High Island
A−218
A−230
A−232
A−422
A−516
A−587
Viosca Knoll
23
157
697
908*
917*
961*
962*
Atwater Valley
10*
11*
23*
66*
67*
327*
533*
24
75
24
50
100
30
34
30
30
30
35
67
30
30
40
30
30
50
100
14
52
98
25
25
25
25
25
67
100
100
50
100
100
3
100
100
50
100
10
10
10
100
100
100
100
100
79
40
*Located in water deeper than 1,000 feet.
15
The developed and undeveloped acreage (including both leases and concessions) that Noble Energy held as of December 31, 2003, is
as follows:
Location
United States Onshore
Alabama
California
Colorado
Kansas
Louisiana
Michigan
Mississippi
Montana
Nevada
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 (5)
Total International
Developed Acreage (1)(2)
Gross Acres
Net Acres
Undeveloped Acreage (2)(3)(4)
Net Acres
Gross Acres
2,368
79,251
93,278
33,712
878
201,622
2,117
137,943
88,076
1,280
27,183
667,708
97,920
38,833
543,986
37,756
214,325
932,820
28,988
7,413
12,355
45,203
123,552
865
65,489
283,865
1,191
60,372
52,833
11,398
34
122,928
826
48,756
33,952
260
11,834
344,384
37,670
12,039
239,863
19,260
97,702
406,534
3,977
4,225
12,355
15,727
58,142
130
4,441
98,997
2,926
5,914
27,636
18,724
36,920
1,876
1,884
4,598
50,996
2,480
685
12,752
114,190
3,232
66,388
351,201
24,381
52,364
443,042
120,960
114,911
755,658
2,426,221
1,617,549
81,050
851,771
266,754
292,572
74,749
418,039
1,701,812
7,730,517
505
2,610
20,817
12,828
11,465
427
51
1,612
49,727
1,833
314
5,833
46,331
2,456
35,973
192,782
14,467
9,422
285,774
58,070
76,625
444,358
2,353,455
808,775
32,420
851,771
92,808
137,681
11,212
110,641
1,309,034
5,707,797
Total (6)
1,884,393
849,915
8,837,376
6,344,937
(1)
Developed acreage is acreage spaced or assignable to productive wells.
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
(2)
working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross
acres expressed as whole numbers and fractions thereof.
Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that
(3)
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 one concession totaling 1,163,865 acres subject to final regulatory approval.
(5)
The Company wrote off its investment in Vietnam and is in the process of assigning its ownership in the two blocks.
If production is not established, approximately 112,617 gross acres (65,080 net acres), 136,362 gross acres (85,015 net acres) and
(6)
128,939 gross acres (79,699 net acres) will expire during 2004, 2005 and 2006, respectively.
16
Item 3. Legal Proceedings.
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.
On October 15, 2002, Noble Gas Marketing, Inc. and Samedan Oil Corporation, 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 $12 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.
On January 13, 2003, the Noble Defendants filed an answer to ENA’s complaint. On January 29, 2003, the Noble Defendants filed the
Motion of Noble Energy Marketing, Inc., as Successor to Noble Gas Marketing, Inc., and Noble Energy, Inc., as Successor to
Samedan Oil Corporation, to Compel Arbitration. On March 4, 2003, the Court issued its Order Governing Mediation of Trading
Cases and Appointing the Honorable Allan L. Gropper as Mediator (the “Mediation Order”) which, among other things, abated this
case and referred it to mediation along with other pending adversary proceedings in the Enron bankruptcy cases which involve
disputes arising from or in connection with commodity trading contracts. Pursuant to the Mediation Order, the Honorable Allan L.
Gropper (United States Bankruptcy Judge for the Southern District of New York) is acting as mediator for this case and the other
trading cases which have been referred to him. The mediation for this case was held on December 17, 2003 and no resolution was
reached.
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 2003.
17
Executive Officers of the Registrant
The following table sets forth certain information, as of March 12, 2004, with respect to the executive officers of the Registrant.
Name
Charles D. Davidson (1)
Alan R. Bullington (2)
Robert K. Burleson (3)
Susan M. Cunningham (4)
Arnold J. Johnson (5)
James L. McElvany (6)
Richard A. Peneguy, Jr. (7)
William A. Poillion, Jr. (8)
Ted A. Price (9)
David L. Stover (10)
Kenneth P. Wiley (11)
Age
54
52
46
48
48
50
53
54
44
46
51
Position
Chairman of the Board, President, Chief Executive Officer and Director
Vice President, International
Vice President, Business Administration and President, Noble Energy
Marketing, Inc.
Senior Vice President, Exploration
Vice President, General Counsel and Secretary
Senior Vice President, Chief Financial Officer and Treasurer
Vice President, Offshore
Senior Vice President, Production and Drilling
Vice President, Onshore
Vice President, Business Development
Vice President, Information Systems
(1)
Charles D. Davidson was elected President and Chief Executive Officer of the Company in October 2000 and Chairman of the
Board in April 2001. Prior to October 2000, he served as President and Chief Executive Officer of Vastar Resources, Inc. (“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 joined ARCO in 1972.
Alan R. Bullington was elected Vice President and General Manager, International Division of Samedan Oil Corporation on
(2)
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.
Robert K. Burleson was elected a Vice President of the Company on April 24, 2001 and has been in charge of the Company’s
(3)
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 with the Company, he was employed by Reliant Energy as Director of Business
Development for its interstate pipeline, Reliant Gas Transmission.
18
(4)
Susan M. Cunningham was elected Senior Vice President of Exploration of the Company in April 2001. 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, appointed a
Vice President in 1998 and responsible, in 1999, for Statoil’s West Africa exploration efforts. She joined Amoco in 1980 as a
geologist and served in exploration and development positions of increasing responsibility until 1997.
Arnold J. Johnson was elected Vice President, General Counsel and Secretary of the Company on February 1, 2004. Prior
(5)
thereto, he served as Associate General Counsel and Assistant Secretary of the Company from January 2001 through January 2004.
Prior thereto, he served as Senior Counsel for BP America, Inc. from October 2000 to January 2001. Mr. Johnson held several
positions as an attorney for Vastar Resources, Inc. and ARCO from March 1989 through September 2000, most recently as Assistant
General Counsel and Assistant Secretary of Vastar Resources from 1997 through 2000. He joined ARCO in 1980 as a landman and
served in land management positions of increasing responsibility until 1989.
James L. McElvany was elected Senior Vice President, Chief Financial Officer and Treasurer of the Company in July 2002. Prior
(6)
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.
Richard A. Peneguy, Jr. was elected a Vice President of the Company on April 24, 2001 and has served as Vice President and
(7)
General Manager, Offshore Division of Samedan Oil Corporation since January 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.
William A. Poillion, Jr. was elected a Senior Vice President of the Company on April 24, 2001 and has served as Senior Vice
(8)
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.
Ted A. Price was elected Vice President of the Company and Division Manager for the Onshore Division on January 29, 2002.
(9)
Previously, he served as Manager of Onshore Exploration since 1999. Mr. Price joined the Company in 1981 as a geologist.
David L. Stover was elected Vice President of Business Development of the Company on December 16, 2002. Previous to his
(10)
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.
Kenneth P. Wiley was elected Vice President−Information Systems of the Company in July 1998. Prior thereto, he served as
(11)
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.
There are no family relationships among any of the Registrant’s officers.
19
PART II
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities.
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.
2003
First quarter
High
Low
Dividends
Per Share
$
38.62
$
33.07
$
.04
Second quarter
Third quarter
Fourth quarter
2002
First quarter
Second quarter
Third quarter
Fourth quarter
$
$
$
$
$
$
$
40.02
40.00
45.99
40.00
40.76
36.34
40.50
$
$
$
$
$
$
$
32.37
35.37
37.48
30.76
34.70
26.65
31.55
$
$
$
$
$
$
$
.04
.04
.05
.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. Pursuant to the records of the transfer agent, as of March 5, 2004, the number of holders of record of Common
Stock was 998. The following chart indicates the common stockholders by category.
March 5, 2004
Individuals
Joint accounts
Fiduciaries
Institutions
Nominees
Foreign
Total−Excluding Treasury Shares
Shares
Outstanding
381,843
56,013
118,890
64,807
57,176,142
319
57,798,014
Sales of Unregistered Securities. The Company owns a 45 percent interest in AMPCO through its 50 percent ownership in AMCCO.
During 1999, AMCCO issued $125 million Series A−2 senior secured notes due December 15, 2004 to fund construction payments
owed in connection with the construction of the methanol plant. The Company includes the $125 million Series A−2 senior notes on
its balance sheet. 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 Stock”), 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.
20
Noble Share Trust holds the 125,000 shares of Series B Preferred Stock 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 Stock 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 Stock, 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
Stock, 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 Stock, 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 Stock 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 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 Stock 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)
2003
2002
Year Ended December 31,
2001
2000
1999
Revenues and Income
Revenues
Net cash provided by operating activities
Income from continuing operations
Net income
Per Share Data
Basic earnings per share:
Income from continuing operations
Net income
Cash dividends
Year−end stock price
Basic weighted average shares outstanding
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 (1)
$
$
$
$
$
$
1,010,986 $
602,770
89,892
77,992
702,578 $
506,955
8,095
17,652
789,513 $
628,154
85,163
133,575
730,657 $
562,578
137,066
191,597
558,887
343,935
28,110
49,461
1.58 $
1.37 $
0.17 $
44.43 $
56,964
0.14 $
0.31 $
0.16 $
37.55 $
57,196
1.51 $
2.36 $
0.16 $
35.29 $
56,549
2.45 $
3.42 $
0.16 $
46.00 $
55,999
0.49
0.87
0.16
21.44
57,005
2,099,741 $
2,842,649
2,139,785 $
2,730,015
1,953,211 $
2,604,255
1,485,123 $
2,002,819
1,242,370
1,543,023
776,021
163,146
50,654
1,073,573
.46
977,116
201,939
69,820
1,009,386
.50
961,118
176,259
75,629
1,010,198
.50
648,567
117,048
61,639
849,682
.44
567,524
83,075
53,877
683,609
.46
(1) Defined as the Company’s total debt plus its equity.
For additional information, see “Item 8. Financial Statements and Supplementary Data” of this Form 10−K.
Operating Statistics – Continuing Operations
Natural Gas
Sales (in millions)
Production (MMcfpd)
Average realized price (per Mcf)
Crude Oil
Sales (in millions)
Production (Bopd)
Average realized price (per Bbl)
Royalty sales (in millions)
2003
2002
Year Ended December 31,
2001
2000
1999
$
$
$
$
$
457.6
336.6
4.13
358.0
36,014
27.72
23.5
$
$
$
$
$
22
341.1
341.0
2.89
252.3
29,114
24.22
15.6
$
$
$
$
$
487.4
355.6
3.86
208.6
24,973
23.49
20.9
$
$
$
$
$
492.0
335.8
4.09
124.9
19,650
18.21
17.3
$
$
$
$
$
327.6
386.6
2.40
124.0
23,690
14.72
14.0
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Noble Energy 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 and Texas); the Mid−Continent Region (Oklahoma and Kansas); and the Rocky
Mountain Region (Colorado, Montana, Nevada, Wyoming and California). The international areas of operations include Argentina,
China, Ecuador, Equatorial Guinea, the Mediterranean Sea (Israel), the North Sea (Denmark, the Netherlands and the United
Kingdom) and Vietnam. The Company also markets domestic crude oil and natural gas production through a wholly−owned
subsidiary, NEMI.
The Company’s accompanying consolidated financial statements, including the notes thereto, contain detailed information that should
be referred to in conjunction with the following discussion.
EXECUTIVE OVERVIEW
Noble Energy’s principal business strategy is to create shareholder value by generating stable cash flow and production from domestic
operations, while generating growth from international projects. In the U.S., the Company has a substantial onshore and offshore asset
base located in established, prolific basins where the Company is aggressively pursuing exploration and exploitation opportunities.
Offshore, exploration focuses on the deepwater and deep shelf areas of the Gulf of Mexico. Internationally, the Company has built a
strong project portfolio and has applied innovative approaches to developing markets for stranded natural gas, including construction
of a natural gas−fired power plant near Machala, Ecuador, and liquefied petroleum gas and methanol plants in Equatorial Guinea.
Over the past two years, the Company has completed major, capital−intensive projects in Ecuador, China, Israel and the first phase of
a two−phase project in Equatorial Guinea. With these important projects completed, international capital commitments are declining
rapidly. At the same time, the projects are contributing significantly to the Company’s financial and operating results.
During 2003, Noble Energy reached several milestones in positioning the Company as a major international competitor among
independent exploration and production companies, including:
First production in China occurred in January 2003;
Initial production began in November 2003 from the Phase 2A expansion project in Equatorial Guinea;
Facilities were commissioned to begin production of natural gas in Israel, with first production in December 2003 and first sales
•
•
•
in February 2004; and
•
Full year of Ecuador power plant operations.
Domestically, an active onshore drilling program led to several discoveries and new production during 2003. Offshore, in the
deepwater region of the Gulf of Mexico, the Company announced an apparent discovery on the Lorien prospect and start of
production from the Boris field. In the shelf region of the Gulf of Mexico, there was new production from the Roaring Fork field
beginning in the fourth quarter. Also during 2003, the Company identified and prepared for sale five packages of domestic non−core
properties. This divestiture program was intended to reduce costs and streamline the business. At the close of the year, sales were
completed on four of the property packages.
2003 was a year of strong financial performance as well:
Net income for 2003 was $78.0 million, a significant increase over 2002 net income of $17.7 million;
Net cash provided by operating activities in 2003 was $602.8 million, an increase of $95.8 million over net cash provided by
•
•
operating activities of $507.0 million in 2002; and
•
year−end 2003, a reduction of $89.3 million from the previous year.
The Company ended the year with a stronger balance sheet – total debt was $929.7 million, net of unamortized discount, at
23
With 2003’s strong financial performance and the decline in international capital commitments, Noble Energy gained enhanced
financial flexibility. Projects in China, Ecuador and Israel are now complete. In Equatorial Guinea, the first phase production is
ramping up and the second phase is scheduled for completion by year−end 2004. The completion of these projects should contribute to
increased amounts of free cash flow. Domestic operations have implemented disciplined business processes that have stabilized
production. As a result, Noble Energy has gained financial and operational flexibility.
CRITICAL ACCOUNTING 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 amounts of assets and liabilities and the disclosures of contingent assets and liabilities at the date
of the consolidated financial statements and the reported amounts of revenues and expenses during the period. When alternatives exist
among various accounting methods, the choice of accounting method can have a significant impact on reported amounts. The
following is a discussion of the Company’s accounting estimates and judgments which management believes are most significant in its
application of generally accepted accounting principles used in the preparation of the consolidated financial statements.
Reserves – All of the reserve data in this Form 10−K are estimates. The Company’s estimates of crude oil and natural gas reserves are
prepared by the Company’s engineers in accordance with guidelines established by the SEC. Reservoir engineering is a subjective
process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating
quantities of proved crude oil and natural gas reserves. Uncertainties include the projection of future production rates and the expected
timing of development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil
and natural gas that are ultimately recovered. Estimates of proved crude oil and natural gas reserves significantly affect the Company’s
depreciation, depletion and amortization (“DD&A”) expense. For example, if estimates of proved reserves decline, the Company’s
DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves would also trigger an
impairment analysis and could result in an impairment charge.
The SEC requested clarification, which the Company provided, as to the Company’s Israel and Equatorial Guinea gas reserves
recorded in excess of existing contract amounts. SEC guidelines do not limit reserve bookings only to contracted volumes if it can be
demonstrated that there is reasonable certainty that a market exists, which the Company believes exists in both of these situations. The
Israel gas contract is for a period of 11 years. The Israel gas market, as estimated by the Israeli Ministry of National Infrastructure,
from 2005 to 2020, is twenty times greater than Noble Energy’s uncontracted net estimated proved reserves. In Equatorial Guinea, the
gas contract, which runs through 2026, is between the field owners and the methanol plant owners. Noble Energy, through its
subsidiaries, holds a working interest in the field as well as an interest in the methanol plant. The Company has recorded reserves
through the end of the concession’s term in 2040. Noble Energy has obtained independent third−party engineer reserve estimates for
both of these projects.
Oil and Gas Properties – The Company accounts for its crude oil and natural gas properties under the successful efforts method of
accounting. The alternative method of accounting for crude oil and natural gas properties is the full cost method. Under the successful
efforts method, costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find
proved reserves and to drill and equip development wells are capitalized. 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. Application of the successful efforts method results in
the expensing of certain costs including geological and geophysical costs, exploratory dry holes and delay rentals, during the periods
the costs are incurred. Under the full cost method, these costs are capitalized as assets and charged to earnings in future periods as a
component of DD&A expense. The Company believes the successful efforts method is the most appropriate method to use to account
for its crude oil and natural gas production activities because during periods of active exploration, this
24
method results in a more conservative measurement of net assets and net income. If the Company had used the full cost method, its
financial position and results of operations would have been significantly different.
Impairment of Oil and Gas Properties – The Company assesses proved crude oil and natural gas properties for possible impairment
when events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. The Company
recognizes an impairment loss when the estimated undiscounted future cash flows from a property are less than the current net book
value. Estimated future cash flows are based on management’s expectations for the future and include estimates of crude oil and
natural gas reserves and future commodity prices and operating costs. Downward revisions in estimates of reserve quantities or
expectations of falling commodity prices or rising operating costs can result in a reduction in undiscounted future cash flows and
could indicate a property impairment. The Company recognized $31.9 million of impairments in 2003, primarily related to a reserve
revision on a property in the Gulf of Mexico after recompletion and remediation activities produced less−than−expected results.
The Company also performs periodic assessments of individually significant unproved crude oil and natural gas properties for
impairment. Management’s assessment of the results of exploration activities, estimated future commodity prices and operating costs,
availability of funds for future activities and the current and projected political climate in areas in which the Company operates impact
the amounts and timing of impairment provisions. In December 2003, the Company elected not to pursue any additional exploration
efforts in the Nam Con Son Basin of Vietnam. As a result, the Company wrote off its investment in Vietnam.
Asset Retirement Obligation – The Company’s asset retirement obligations (“ARO”) consist primarily of estimated costs of
dismantlement, removal, site reclamation and similar activities associated with its oil and gas properties. Statement of Financial
Accounting Standard (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations,” requires that the discounted fair value of a
liability for an ARO be recognized in the period in which it is incurred with the associated asset retirement cost capitalized as part of
the carrying cost of the oil and gas asset. The recognition of an ARO requires that management make numerous estimates,
assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; estimated probabilities, amounts
and timing of settlements; the credit−adjusted risk−free rate to be used; inflation rates; and future advances in technology. In periods
subsequent to initial measurement of the ARO, the Company must recognize period−to−period changes in the liability resulting from
the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in
the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions
thereto, is charged to expense through DD&A. At December 31, 2003, the Company’s balance sheet included a liability for ARO of
$124.5 million.
Derivative Instruments and Hedging Activities – The Company uses various derivative financial instruments to hedge its exposure to
price risk from changing commodity prices. The Company does not enter into derivative or other financial instruments for trading
purposes. Management exercises significant judgment in determining types of instruments to be used, production volumes to be
hedged, prices at which to hedge and the counterparties and their creditworthiness. The Company accounts for its derivative
instruments under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” For derivative instruments that
qualify as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in accumulated other
comprehensive income (“AOCI”) until the forecasted transaction is recognized in earnings. Therefore, prior to settlement of the
derivative instruments, changes in the fair market value can cause significant increases or decreases in AOCI. For derivative
instruments that do not qualify as cash flow hedges, changes in fair value must be reported in the current period, rather than in the
period in which the forecasted transaction occurs. This may result in significant increases or decreases in current period net income.
Deferred Tax Asset Valuation Allowance – The Company’s balance sheet includes deferred tax assets related to deductible temporary
differences and operating loss carryforwards. Ultimately, realization of a deferred tax benefit depends on the existence of sufficient
taxable income within the carryback/carryforward period to absorb future deductible temporary differences or a carryforward. In
assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all
of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in
determining whether a valuation
25
allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and
tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive
evidence. As a result of management’s current assessment, the Company maintains a valuation allowance against a portion of its
deferred tax assets. The valuation allowances associated with certain foreign loss carryforwards have decreased from $21.1 million in
2002 to $14.5 million in 2003. This change was due to the elimination of the carryforward and offsetting valuation allowance
associated with Vietnam, the elimination of the valuation allowance associated with Israel and the partial elimination of the valuation
allowance associated with China. Because of the relatively short carryforward period in China and the lack of a long−term fixed price
contract, the valuation allowance associated with China was not fully eliminated. The Company will continue to monitor facts and
circumstances in its reassessment of the likelihood that operating loss carryforwards and other deferred tax attributes will be utilized
prior to their expiration. As a result, the Company may determine that the deferred tax asset valuation allowance should be increased
or decreased. Such changes would impact net income through offsetting changes in income tax expense.
Pension Plan – The Company sponsors a defined benefit pension plan and other postretirement benefit plans. The actuarial
determination of the projected benefit obligation and related benefit expense requires that certain assumptions be made regarding such
variables as expected return on plan assets, discount rates, rate of compensation increase, estimated employee turnover rates and
retirement dates, lump−sum election rates, mortality rate, retiree utilization rates for health care services and health care cost trend
rates. The selection of assumptions requires considerable judgment concerning future events and has a significant impact on the
amount of the obligation recorded on the Company’s balance sheets and on the amount of expense included on the Company’s
statements of operations, as well as on funding.
Noble Energy bases its determination of the asset return component of pension expense on a market−related valuation of assets, which
reduces year−to−year volatility. This market−related valuation recognizes investment gains or losses over a five−year period from the
year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using
the market−related value of assets and the actual return based on the fair value of assets. Since the market−related value of assets
recognizes gains or losses over a five−year period, the future value of assets will be impacted as previously deferred gains or losses
are recorded. As of December 31, 2003, the Company had cumulative asset losses of approximately $7.0 million, which remain to be
recognized in the calculation of the market−related value of assets.
The Company utilizes the services of an outside actuarial firm to assist in the calculations of the projected benefit obligation and
related costs. The Company and its actuaries use historical data and forecasts to determine assumptions. In selecting the assumption
for expected long−term rate of return on assets, the Company considers the average rate of earnings expected on the funds to be
invested to provide for plan benefits. This includes considering the plan’s asset allocation, historical returns on these types of assets,
the current economic environment and the expected returns likely to be earned over the life of the plan. It is assumed that the
long−term asset mix will be consistent with the target asset allocation of 70 percent equity and 30 percent fixed income, with a range
of plus or minus 10 percent acceptable degree of variation in the plan’s asset allocation. The discount rate is determined by analyzing
the interest rates implicit in current annuity contract prices and available yields on high quality fixed income securities. By definition,
discount rates reflect rates at which pension benefits could be effectively settled.
The expected return assumption for 2004 is 8.5 percent and the assumed discount rate for 2004 is 6.25 percent, both of which are the
same as 2003.
LIQUIDITY AND CAPITAL RESOURCES
Overview
The Company’s primary cash needs are to fund capital expenditures related to the acquisition, exploration and development of crude
oil and natural gas properties, to repay outstanding borrowings or to pay other contractual commitments, for interest payments on debt,
to pay cash dividends on common stock and to fund contributions to the
26
Company’s pension and postretirement benefit plans. The Company’s traditional sources of liquidity are its cash on hand, cash flows
from operations and available borrowing capacity under its credit facilities. Funds may also be generated from occasional sales of
non−strategic crude oil and natural gas properties. The Company made significant progress during 2003 in improving liquidity and
financial flexibility. Reduction in international capital commitments due to completion of major capital−intensive projects is expected
to increase flexibility and liquidity in 2004. With these projects completed or nearing completion, international capital commitments
are declining rapidly while, at the same time, they are beginning to contribute to the Company’s financial and operating results. A
$100 million increase in the Company’s 364−day credit facility will also provide increased liquidity in 2004.
The Company improved its balance sheet leverage during 2003 and achieved a reduction in its ratio of debt−to−book capital (defined
as the Company’s total debt plus its equity) to 46 percent at December 31, 2003, compared to 50 percent at December 31, 2002. The
Company reduced total debt by $89.3 million during 2003.
The Company’s current ratio (current assets divided by current liabilities) was .73:1 at December 31, 2003, compared with .66:l at
December 31, 2002. The improvement in the current ratio in 2003, as compared to 2002, resulted from increases in year−end cash and
cash equivalents, accounts receivable and derivative financial instruments in current assets which were partially offset by increases in
accounts payable, current installments of long−term debt and derivative financial instruments in current liabilities. In 2003, total
current assets increased by 54 percent as compared to 2002 while total current liabilities increased only 39 percent for the same period.
Cash Flows
Operating Activities – The Company reported a $95.8 million year−over−year increase in cash flows from operating activities. Net
cash provided by operating activities totaled $602.8 million for the year ended December 31, 2003, compared to $507.0 million in
2002 and $628.2 million in 2001. The 2003 increase was driven by an overall production increase of four percent and higher realized
commodity prices. The increase was also impacted by higher distributions from the Company’s unconsolidated methanol subsidiary
and a growing contribution from electricity sales. The $121.2 million decrease in 2002, as compared to 2001, was due primarily to
lower natural gas prices, partially offset by higher crude oil prices and production volumes.
Investing Activities – Net cash used in investing activities totaled $444.8 million, $577.5 million and $871.7 million for the years
ending December 31, 2003, 2002 and 2001, respectively. The Company’s investing activities relate primarily to expenditures made for
the exploration and development of oil and gas properties and have been decreasing due to declining capital commitments. During
2003, expenditures were offset by the receipt of $81.1 million from sales of non−core assets. Additionally, the Company funded the
Aspect acquisition in 2001 for approximately $97.8 million, net of $9.3 million cash acquired and 405,778 shares of treasury stock.
Financing Activities – Net cash used in financing activities totaled $111.0 million for the year ending December 31, 2003. Net cash
provided by financing activities totaled $12.8 million and $293.6 million for the years ending December 31, 2002 and 2001,
respectively. Financing activities consist primarily of proceeds from and repayments of bank debt, repayment of notes payable, the
payment of cash dividends and proceeds from the exercise of stock options. Also included in financing activities was the repayment of
an obligation of $36.6 million related to treasury stock in 2003. The decrease in net cash provided by financing activities in 2003 as
compared to 2002 resulted from repayments of bank debt and repayment of the treasury stock obligation in addition to a decrease in
bank borrowings. The decrease in net cash provided by financing activities in 2002 as compared to 2001 related primarily to a
decrease in bank borrowings.
27
Capital Expenditures
Capital expenditures incurred in oil and gas activities, downstream projects, acquisitions, and corporate and other consisted of the
following:
(in thousands)
Oil and gas mineral interests, equipment and facilities
Downstream projects
Aspect acquisition
Corporate and other
Total capital expenditures (1)
2003
492,764
45,134
6,119
544,017
$
$
Year Ended December 31,
2002
2001
$
$
543,967
57,646
3,185
604,798
$
$
667,499
95,716
97,792
1,932
862,939
Total capital expenditures include seismic, lease rentals and other miscellaneous expenditures, which are expensed through the
(1)
statements of operations and are not included in capital expenditures from investing activities.
Capital expenditures from investing activities consisted of the following:
(in thousands)
Capital expenditures (1)
Aspect acquisition, net of cash acquired
Total capital expenditures from investing activities
2003
527,386
527,386
$
$
Year Ended December 31,
2002
$
$
595,739
595,739
$
$
2001
738,706
97,792
836,498
Capital expenditures do not include expenditures for the methanol plant. Those expenditures are included in cash flows from
(1)
investing activities – investment in unconsolidated subsidiaries.
Capital expenditures budget
$
510,000
$
519,000
$
625,000
Capital expenditures have shown year−over−year declines of $60.8 million or 10 percent (2003 to 2002) and $258.1 million or 30
percent (2002 to 2001). These decreases in spending are the result of declining capital commitments due to the completion, or near
completion, of major capital−intensive projects in international locations.
During 2003, the Company expended $544.0 million compared to a budget of $510 million. The primary reason for the additional
capital expenditures was due to the acceleration of the initial costs to begin the Phase 2B expansion in Equatorial Guinea. During
2002, the Company expended $604.8 million compared to a budget of $519 million. The primary additional capital expenditures were
for the completion of the gas−to−power project in Ecuador and the continued development of the Israel project. During 2001, the
Company expended $862.9 million compared to a budget of $625 million. The primary additional expenditures in 2001 were for the
Aspect acquisition, which was $97.8 million and not included in the budget, and the completion of the methanol plant in Equatorial
Guinea, along with the development of the gas−to−power project in Ecuador.
2004 Budget – The Company’s 2004 capital expenditure budget totals $459.7 million, a decline of 15 percent compared to 2003 actual
capital expenditures. The reduced budget results from the completion of two major international projects, the Phase 2A condensate
expansion project in Equatorial Guinea and the Mari−B natural gas project in Israel.
The 2004 capital budget has allocated approximately 35 percent to exploration opportunities and 65 percent to production and
development projects. The budget allocates $270.4 million, or 59 percent, to domestic spending with approximately two−thirds for the
offshore division and one−third for the onshore division. Of the total domestic capital budget, approximately 55 percent is for
exploration and 45 percent is for production and development. The budget allocates $189.3 million, or 41 percent, to international
expenditures with 84 percent for production and development
28
projects. Noble Energy has planned expenditures allocated to regions where the Company is most active, including the Middle East
and Africa ($95.3 million), the Far East and Latin America ($73.8 million) and the North Sea ($20.2 million). The Company expects
that its 2004 capital expenditure budget will be funded primarily from cash flow from operations and proceeds from the sale of its
offshore asset package expected to occur during the first half of 2004. The Company will evaluate its level of capital spending
throughout the year based upon drilling results, commodity prices, cash flows from operations and property acquisitions.
Acquisitions – The Company has made no significant acquisitions since 2001 when it acquired interests in certain wells located along
the Texas and Louisiana Gulf Coast and an interest in future drilling prospects from Aspect Energy for $97.8 million, net of $9.3
million cash acquired and 405,778 shares of treasury stock.
Asset Sales
The Company has sold a number of non−strategic crude oil and natural gas properties over the past three years. Proceeds from asset
sales totaled $81.1 million, $20.4 million and $1.4 million in 2003, 2002 and 2001, respectively. Sales of properties during 2003
included reserves of approximately 108 Bcfe, or four percent, of year−end 2002 proved reserves. Sales of properties during 2002
included reserves of approximately 25 Bcfe. The Company believes the disposition of non−strategic properties allows it to concentrate
efforts on strategic properties and reduce leverage.
Financing Activities
Debt – The Company’s debt totaled $933.7 million at December 31, 2003, of which $776.0 million was long−term with maturities
ranging from 2005 to 2097. The Company’s $125 million Series A−2 Notes, $7.9 million of the Aspect acquisition note and $20.7
million of Israel debt are due during 2004 and are classified as short−term on the Company’s consolidated balance sheets. The
Company expects to fund the repayments primarily from a combination of operating cash flows, draw downs of the credit facilities
and proceeds from the sale of non−core properties.
The Company has a $400 million credit agreement due November 30, 2006. The credit facility is with certain commercial lending
institutions and 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, 2003, there was $140 million borrowed against this credit agreement leaving $260 million of unused borrowing
capacity.
The Company entered into a new $300 million 364−day credit agreement effective November 3, 2003, which represents an increase in
capacity of $100 million over the previous facility. The credit agreement is with certain commercial lending institutions and 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, 2003, there was $190 million borrowed against this credit agreement leaving $110 million of unused borrowing
capacity. The agreement has a maturity date of October 28, 2004 for the revolving commitment and a final maturity date of
October 28, 2005 for the term commitment that includes any balance remaining after the revolving commitment matures.
During 2004, a subsidiary of the Company borrowed a total of $150.0 million from certain commercial lending institutions. The
interest rate on the borrowing is London Interbank Offering Rate (“LIBOR”) plus an effective range of 60 to 130 basis points
depending upon credit rating and the borrowing is for a term of five years. Proceeds were used to reduce amounts due under the $400
million credit agreement.
Financial covenants on both the $400 million and $300 million credit facilities include the following: (a) the ratio of Earnings Before
Interest, Taxes, Depreciation and Exploration Expense (“EBITDAX”) to 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 entities may not be less
than $800 million at any time.
29
The Company occasionally enters into forward contracts or swap agreements to hedge exposure to interest rate risk. At
December 31, 2003, the Company’s consolidated balance sheet included a payable of $4.0 million related to an outstanding interest
rate lock.
The Company made cash interest payments of $46.0 million, $47.6 million and $41.7 million during 2003, 2002 and 2001,
respectively.
Dividends – The Company paid quarterly cash dividends of four cents per share from 1989 through the third quarter 2003. In
October 2003, the Company’s Board of Directors declared a quarterly cash dividend of five cents per common share. This payment
represents an increase of one cent per share, or 25 percent, over the Company’s previous quarterly payment of four cents per share.
Total dividends paid during 2003 increased $.6 million, or seven percent, over 2002 due to the higher dividend rate. The amount of
future dividends will be determined on a quarterly basis at the discretion of the Company’s Board of Directors and will depend on
earnings, financial condition, capital requirements and other factors.
Stock Repurchase Program – In accordance with a Board−approved stock repurchase forward program, one of the Company’s banks
purchased 1,044,454 shares of Company stock on the open market during 2001 and 2002. During the second quarter of 2003, the
Company adopted SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.”
As a result, the Company recorded an additional 1,044,454 shares of treasury stock at a cost of $36.6 million and an obligation of
$36.6 million. In December 2003, the Company paid the obligation in full.
Exercise of Stock Options – The Company received $24.7 million, $7.7 million and $12.3 million from the exercise of stock options
during 2003, 2002 and 2001, respectively. Proceeds received by the Company from the exercise of stock options fluctuate primarily
based on the price at which the Company’s common stock trades on the New York Stock Exchange in relation to the exercise price of
the options issued. During 2003 and 2001, the Company’s stock reached higher sales prices than during 2002, resulting in the exercise
of more options and more proceeds to the Company. In addition, during 2003, stock options were exercised at a higher average price
than during 2001 and 2002.
Other
Contributions to Pension and Other Postretirement Benefit Plans – The Company made contributions of $14.6 million to its pension
and other postretirement benefit plans during 2003, $10.9 million during 2002 and $3.7 million during 2001. The Company expects to
make cash contributions of $2.0 million to its pension plan during 2004. The decrease in the expected contribution for 2004 is due
primarily to the higher actual return on pension plan assets experienced during 2003 and an expectation of a continued positive return
on plan assets during 2004 due to the recovery of market conditions. During 2003, the actual return on plan assets was a positive $7.6
million, while the returns in 2002 and 2001 were a negative $3.5 million and a negative $1.5 million, respectively. The value of the
plan assets has tended to follow market performance. The expected return assumption for 2004 is 8.5 percent and the assumed
discount rate for 2004 is 6.25 percent, both of which are the same as 2003. A one percent decrease in the expected return on plan
assets would have resulted in an increase in benefit expense of $.7 million in 2003.
Federal Income Taxes – The Company made cash payments for federal income taxes of $55.5 million during 2003 and $66.1 million
during 2001. During 2002, the Company received a federal tax refund of $40.4 million. The refund related to large estimated tax
payments made during the first half of 2001 followed by a period of declining commodity prices, which resulted in lower taxable
income by the end of 2001.
Contingencies – During 2003, the Company paid $1.9 million in settlement of two legal proceedings conducted in the ordinary course
of business. During 2002, the Company paid $7.0 million in settlement of a legal proceeding conducted in the ordinary course of
business. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain
matters, as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when
it is probable that a liability has been incurred and the amount can be reasonably estimated.
30
Contractual Obligations
The following table summarizes the Company’s contractual obligations as of December 31, 2003.
(in thousands)
Contractual
Obligations
Outstanding debt
Asset retirement obligation
Drilling obligations
Building lease
Total contractual cash obligations
Total
933,674 $
124,537
3,924
14,292
1,076,427 $
$
$
Less Than
1 Year
Payments Due by Period
1 to 3
Years
4 to 5
Years
153,674 $
1,023
3,924
1,588
160,209 $
330,000 $
63,034
$
19,489
4,764
397,798 $
3,176
22,665 $
After 5
Years
450,000
40,991
4,764
495,755
In addition, in the ordinary course of business, the Company maintains letters of credit in support of certain performance obligations.
Outstanding letters of credit totaled approximately $18 million at December 31, 2003.
RESULTS OF OPERATIONS
Net Income and Revenues
The Company’s net income for 2003 was $78.0 million, an increase of $60.3 million from 2002. The increase was due to the
following: crude oil sales increased $106.9 million, natural gas sales increased $123.2 million and income from unconsolidated
subsidiaries increased $31.1 million. The increases were offset by increased oil and gas operations expense (lease operating expense,
workover expense, production taxes and other related lifting costs from continuing operations) of $40.5 million, increased DD&A of
$72.5 million, a non−cash impairment of $31.9 million, a $9.3 million increase in accretion of asset retirement obligation, a non−cash
pre−tax charge for change in accounting principle of $9.0 million and a $4.8 million increase in selling, general and administrative
(“SG&A”). In addition, loss from discontinued operations increased $15.6 million. The decrease of $115.9 million in net income for
2002 compared to 2001 was due to a $151.3 million decrease in natural gas sales, offset by a $43.4 million increase in crude oil sales.
31
Natural Gas Information
Natural gas revenues increased 35 percent in 2003, compared to 2002, due to a 43 percent increase in natural gas prices, offset by a
one percent decrease in daily natural gas production. Natural gas revenues for 2002, compared to 2001, decreased 30 percent due to a
25 percent decrease in natural gas prices coupled with a four percent decrease in daily natural gas production. The table below depicts
average daily natural gas production and prices from continuing operations by area for the last three years.
United States
North Sea
Equatorial Guinea (1)
Other International (2)
Total (3)
2003
2002
2001
Mcfpd
Price
Mcfpd
Price
Mcfpd
Price
260,560
13,861
39,906
22,284
336,611
$
$
$
$
$
4.75
3.86
.25
.41
4.13
280,836
16,991
34,382
8,799
341,008
$
$
$
$
$
3.24
3.14
.25
.38
2.89
311,663
17,830
24,488
1,651
355,632
$
$
$
$
$
4.21
3.51
.25
.95
3.86
(1)
Natural gas in Equatorial Guinea is under a 25−year contract for $.25 per MMBTU.
Ecuador natural gas volumes are included in Other International production, but are not included in natural gas sales revenues
(2)
and average price for 2003 and 2002. Because the gas−to−power project in Ecuador is 100 percent owned by Noble Energy,
intercompany natural gas sales are eliminated for accounting purposes.
Reflects a reduction of $.44 per Mcf in 2003, and increases of $.05 per Mcf in 2002 and $.04 per Mcf in 2001 from hedging in
(3)
the United States.
The 51,103 Mcfpd decline in natural gas production for the United States from 2001 to 2003 is the result of reduced domestic drilling
and natural decline rates for properties in the Gulf of Mexico and the onshore Gulf Coast region. The 3,969 Mcfpd decline in natural
gas production for the North Sea from 2001 to 2003 is the result of natural gas decline rates for properties in the United Kingdom
section of the North Sea. The 15,418 Mcfpd increase in natural gas production for Equatorial Guinea from 2001 to 2003 is the result
of the startup of the methanol plant in May 2001 and the expansion of the Phase 2A project. The 20,633 Mcfpd increase in natural gas
production for Other International from 2001 to 2003 is the result of the startup of the gas−to−power project in Ecuador during 2002.
2003 Daily Production by Quarter
Natural Gas
Crude Oil
32
Crude Oil Information
Crude oil revenues increased 42 percent during 2003, compared to 2002, due to a 14 percent increase in crude oil prices and a 24
percent increase in daily crude oil production. Crude oil revenues for 2002, compared to 2001, increased 20 percent due to a three
percent increase in crude oil prices coupled with a 17 percent increase in daily crude oil production. The table below depicts average
daily crude oil production and prices from continuing operations by area for the last three years.
United States
North Sea
Equatorial Guinea
Other International
Total (1)
2003
2002
2001
Bopd
Price
Bopd
Price
Bopd
Price
16,084
7,412
6,377
6,141
36,014
$
$
$
$
$
26.21
29.95
27.93
28.75
27.72
13,187
7,847
5,259
2,821
29,114
$
$
$
$
$
23.29
25.15
23.88
26.58
24.22
12,926
4,688
4,620
2,739
24,973
$
$
$
$
$
23.02
23.36
23.03
26.67
23.49
Reflects a reduction of $1.01 per Bbl in 2003, $.02 per Bbl in 2002 and an increase of $.01 per Bbl in 2001 from hedging in the
(1)
United States.
The 3,158 Bopd increase in crude oil production for the United States from 2001 to 2003 is the result of success of the Company’s
deepwater projects in the Gulf of Mexico region. The 2,724 Bopd increase in crude oil production for the North Sea from 2001 to
2003 is the result of commencement of production from the Hanze field, offshore in the Netherlands in late 2001. The 1,757 Bopd
increase in crude oil production for Equatorial Guinea from 2001 to 2003 is the result of the continued development of the Alba field
and the expansion of the Phase 2A project. The 3,402 Bopd increase in crude oil production for Other International from 2001 to 2003
is the result of the startup of the CDX field, located in South Bohai Bay off the coast of China, in January 2003.
Electricity Sales − Ecuador Integrated Power Project
The Company, through its subsidiaries, EDC Ecuador Ltd. and MachalaPower Cia. Ltda., has a 100 percent ownership interest in an
integrated gas−to−power project. The project includes the Amistad natural gas field, offshore Ecuador, which supplies fuel to the
Machala power plant.
During 2003, the first full year of operations, the combined project generated $7.2 million of operating income from the generation of
751,689 MW of electricity. The average sales price was 7.7 cents per Kwh.
During 2002, after commencement of commercial electricity generation in mid−September, the Machala power plant contributed $2.3
million of operating income from generation of 269,229 MW of electricity. The average sales price was 6.8 cents per Kwh.
Income from Unconsolidated Subsidiaries
Methanol operations produced $40.6 million, $9.5 million and $7.0 million of operating income, net to Noble Energy’s interest, during
2003, 2002 and 2001, respectively. AMPCO, an unconsolidated subsidiary in which the Company owns a 45 percent interest, owns a
methanol plant in Equatorial Guinea that began production of commercial grade methanol during the second quarter of 2001. The
Company’s share of AMPCO methanol sales volumes was 122 million gallons in 2003, 105 million gallons in 2002 and 54 million
gallons in 2001. Average realized methanol prices were $.65 per gallon, $.43 per gallon and $.39 per gallon for 2003, 2002 and 2001,
respectively.
33
Derivative Financial Instruments and Hedging Activities
The Company, from time to time, uses various derivative instruments in connection with anticipated crude oil and natural gas sales to
minimize the impact of product price fluctuations. Such instruments include fixed price hedges, variable to fixed price swaps, costless
collars and other contractual arrangements. Although these derivative instruments 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. During 2003,
2002 and 2001, the Company included a $67.5 million reduction of sales and increased sales of $5.9 million and $5.1 million,
respectively, related to its cash flow hedges in oil and gas sales and royalties.
Costs and Expenses
Crude oil and natural gas operations expense from continuing operations increased $40.5 million in 2003 compared to 2002. The
increase in crude oil and natural gas operating expense was due to several factors, including new operations in China, increased
production and the startup of Phase 2A in Equatorial Guinea, new production in the Gulf of Mexico and higher production taxes.
Crude oil and natural gas operating expense increased $1.7 million in 2002 compared to 2001.
The table below depicts the crude oil and natural gas operations expense from continuing operations by area for the last three years.
(in thousands)
2003
Lease operating (1)
Production taxes
Workover expense
Total operations expense
2002
Lease operating (1)
Production taxes
Workover expense
Total operations expense
2001
Lease operating (1)
Production taxes
Workover expense
Total operations expense
Consolidated
United
States
North
Sea
Israel(2)
Equatorial
Guinea
Other
Int’l
$
$
$
$
$
$
120,060
19,473
6,303
145,836
82,168
14,315
8,875
105,358
79,733
8,829
15,094
103,656
$
$
$
$
$
$
75,356
14,601
6,303
96,260
61,217
12,284
8,880
82,381
63,169
8,686
15,094
86,949
$
$
$
$
$
$
10,662
10,662
10,817
(5)
10,812
6,075
6,075
$
$
$
$
$
$
$
$
$
$
$
$
16,319
$
17,723
4,872
16,319
$
22,595
9,848
$
286
2,031
9,848
$
2,317
6,775
$
3,714
143
6,775
$
3,857
Lease operating expense includes labor, fuel, repairs, replacements, saltwater disposal, ad valorem taxes and other related lifting
(1)
costs.
(2)
Production did not begin until 2004.
In 2003, DD&A expense from continuing operations increased $72.5 million compared to 2002. The increase was primarily due to
higher domestic DD&A rates and increased production volumes. The unit rate of DD&A per BOE was $9.20 in 2003. Included in
DD&A for 2003 is $20.6 million of abandoned assets expense and $20.2 million of DD&A related to asset retirement obligations,
which increased DD&A by $1.26 per BOE. In 2002, DD&A expense increased
34
$3.4 million compared to 2001. The unit rate of DD&A per BOE was $7.55 in 2002 and $7.58 in 2001. The table below depicts the
DD&A from continuing operations for the years ended December 31:
(in thousands)
United States
North Sea
Israel
Equatorial Guinea
Other International and Corporate
Total DD&A Expense
2003
2002
2001
$
$
254,041
28,219
40
6,115
20,928
309,343
$
$
192,708
28,279
31
5,849
10,014
236,881
$
$
202,732
16,537
23
3,889
10,335
233,516
The Company adopted SFAS No. 143 on January 1, 2003 and recognized, as the fair value of asset retirement obligations, $109.4
million related to the United States and $15.1 million related to the North Sea. Due to the adoption of SFAS No. 143, the Company
recognized a charge for this cumulative effect of change in accounting principle of $5.8 million ($9.0 million net of $3.2 million tax).
The Company had previously accumulated a provision for future dismantlement and restoration costs of $84.1 million at
December 31, 2002. At December 31, 2003, the total asset retirement obligations of $199.3 million consist of $175.9 million for the
United States and $23.4 million for the North Sea and are included in future production and development costs for purposes of
estimating the future net revenues relating to the Company’s proved reserves.
Crude oil and natural gas exploration expense consists of dry hole expense, unproved lease amortization, seismic, staff expense and
other miscellaneous exploration expense, including lease rentals. The table below depicts the exploration expense by area for the last
three years.
(in thousands)
2003
Dry hole expense
Unproved lease amortization
Seismic
Staff expense
Other
Total exploration expense
2002
Dry hole expense
Unproved lease amortization
Seismic
Staff expense
Other
Total exploration expense
2001
Dry hole expense
Unproved lease amortization
Seismic
Staff expense
Other
Total exploration expense
Impairment of Operating Assets
Consolidated
United
States
North
Sea
Israel
Equatorial
Guinea
Other
Int’l
$
$
$
$
$
$
63,637
33,381
17,674
30,182
3,944
148,818
81,396
21,254
20,492
24,928
2,631
150,701
99,684
17,213
15,607
17,148
2,444
152,096
$
$
$
$
$
$
32,408
25,296
15,903
17,483
3,601
94,691
64,449
19,426
14,282
20,081
2,457
120,695
54,810
15,112
13,328
14,431
2,811
100,492
$
$
$
$
$
$
4,023
1,264
1,662
3,105
449
10,503
544
178
827
2,833
828
5,210
28,992
1,725
2,209
1,605
419
34,950
$
$
$
$
$
$
6,711
900
$
214
$
51
83
7,825
$
134
$
$
$
1,341
900
1,671
54
2,625
$
1,341
$
$
$
375
5
39
380
$
39
$
20,495
5,921
58
9,297
(106)
35,665
16,403
750
2,371
1,960
(654)
20,830
15,882
1
26
1,112
(786)
16,235
The Company recognized $31.9 million of impairments in 2003, primarily related to a reserve revision on the East Cameron 338 field
in the Gulf of Mexico after recompletion and remediation activities produced less−than−expected results. An analysis of the
performance response of the field resulted in a reduction in proved reserves of 2.2 MMBoe.
35
The impairment should result in substantially lower depletion costs in 2004. The Company recorded no operating asset impairments
during 2002 and 2001. 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 expenses increased $4.8 million in 2003 compared to 2002 and increased $3.5 million in 2002 compared to 2001. The increase
in SG&A expenses for 2003 is due to increased corporate governance costs, professional fees and other costs related to
Sarbanes−Oxley compliance and increased salary expense. The increase in 2002 compared to 2001 is due to increased salary and legal
expense, as well as increased costs associated with the Company’s international expansion.
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, net of cost of goods sold, as GMP proceeds and NEMI’s expenses as GMP. All intercompany sales and
expenses have been eliminated in the Company’s consolidated financial statements.
The GMP proceeds less expenses for NEMI are reflected in the table below.
(in thousands, except margins)
(amounts include inter−
company eliminations)
Proceeds (1)
Expenses
Transportation
General and administrative
Total Expenses
Gross Margin
Traded Volumes − Bbls/MMBTU
Margin per Bbl/MMBTU
2003
2002
2001
Crude
Oil
31,867
21,456
182
21,638
10,229
8,324
1.23
$
$
$
$
Natural
Gas
36,291
$
28,844
8,632
37,476
$
(1,185) $
239,311
(.01) $
$
$
$
$
Crude
Oil
26,824
20,323
802
21,125
5,699
6,787
.84
$
$
$
$
Natural
Gas
37,693
$
Crude
Oil
26,359
29,000
3,857
32,857
4,836
276,626
.02
$
$
$
19,739
199
19,938
6,421
6,748
.95
Natural
Gas
38,281
28,818
3,176
31,994
6,287
278,944
.02
$
$
$
$
The Company has reclassified all periods to present GMP activities on a net rather than a gross basis in accordance with
(1)
Emerging Issues Task Force (“EITF”) 02−03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts.”
NEMI, from time to time, employs various derivative instruments in connection with its purchases and sales of third−party production
to lock in profits or limit exposure to natural 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 records gains and losses on
derivative instruments using mark−to−market accounting. NEMI recorded a loss of $.2 million, a gain of $.9 million and a loss of $.5
million in GMP proceeds during 2003, 2002 and 2001, respectively, related to derivative instruments.
Interest Expense
Interest rates have consistently decreased over the past three years while Company borrowings have steadily increased, peaking early
in 2003. Throughout the remainder of the year, the Company steadily paid down its debt resulting in a year−over−year decrease of
$2.9 million in interest expense at December 31, 2003 compared to the same period in
36
2002. Interest expense totaled $64.0 million at December 31, 2002, which was a $10.0 million increase over interest expense of $54.0
million at December 31, 2001. The Company believes that interest rates will remain stable in 2004 and expects to continue paying
down its debt throughout the year, which should result in lower interest expense at year−end 2004.
Pension Expense
The Company recognized net periodic benefit cost related to its pension and other postretirement benefit plans of $7.9 million, $8.5
million and $5.7 million during 2003, 2002 and 2001, respectively. This expense included an expected return on pension plan assets of
$5.9 million, $5.5 million and $4.9 million during 2003, 2002 and 2001, respectively.
Allowance for Doubtful Accounts
The Company is exposed to credit risk and takes reasonable steps to protect itself from nonperformance by its debtors, but is not able
to predict sudden changes in its debtors’ creditworthiness. The Company periodically assesses its provision for bad debt allowance.
The Company had allowances for doubtful accounts as of December 31, 2003 and 2002 of $6.3 million and $1.5 million, respectively.
The increase in the allowance in 2003 compared to 2002 was due primarily to an allowance of $4.7 million related to financial
derivative contracts with one of the Company’s counterparties.
Income Taxes
Income tax expense associated with continuing operations increased to $51.7 million in 2003 from $19.8 million in 2002 primarily
from the increase in income. However, the effective income tax rate decreased to 36.5 percent in 2003 from 70.9 percent in 2002.
During 2003, the Company’s income from international operations increased over 2002, but represented a smaller proportion of the
Company’s total income. Some of the countries in which the international operations were conducted have a higher statutory income
tax rate than the United States. Also impacting the effective rate in 2003 was the realization of approximately $15.6 million of tax
benefits for certain prior year costs incurred in Israel and Vietnam.
The $45.2 million decrease in income tax expense for 2002 was due to a $122.2 million decrease in income from continuing
operations offset by an increase in the effective income tax rate. The effective income tax rate on income from continuing operations
increased to 70.9 percent in 2002 from 43.3 percent in 2001. During 2002, a larger proportion of the Company’s income was from
international operations. Some of the countries in which international operations are conducted have a higher statutory income tax rate
than the United States. In the Netherlands, the Company had significantly higher income in 2002 compared to 2001 due primarily to a
full year of production from the Hanze field. In Equatorial Guinea, the Company had higher income in 2002 compared to 2001 from a
full year of the methanol plant’s operations and the impact of nondeductible interest expense. In the United Kingdom, the Company
had higher income in 2002 compared to 2001 and was impacted by an increase in the country’s corporate tax rate. In Ecuador, the
Company had no income prior to 2002.
Discontinued Operations
Pursuant to SFAS No. 144, “Accounting for the Impairment or Disposal of Long−Lived Assets,” the Company’s consolidated
financial statements have been reclassified for all periods presented to reflect the operations and assets of the properties being sold as
discontinued operations. The net income from discontinued operations was classified on the consolidated statements of operations as
“Discontinued Operations, Net of Tax.”
During 2003, the Company identified five domestic property packages for disposition. Bids have now been received on all five
packages. During 2003, property sales closed on four of the five packages, with the remaining property package expected to close
during the first half of 2004. Total pretax proceeds on all five packages, before closing adjustments, are expected to be in excess of
$110.0 million.
37
The Company recorded a loss, net of tax, related to discontinued operations of $6.1 million in 2003. Included in the discontinued
operations loss was a $59.2 million ($38.5 million, net of tax) non−cash write down to market value for certain of the five property
packages. The Company has reclassified the results of operations associated with the five property packages for 2001 and 2002 to
discontinued operations. This reclassification did not have an effect on net income as previously reported for 2001 and 2002. As a
result of the reclassification, oil and gas sales and royalties are lower, as well as the associated oil and gas operations and DD&A
expense.
Summarized results of discontinued operations are as follows:
(dollars in thousands)
Revenues:
Oil and gas sales and royalties
Costs and Expenses:
Write down to market value and realized loss
Oil and gas operations
Depreciation, depletion and amortization
Income (Loss) Before Income Taxes
Income Tax Provision (Benefit)
Income (Loss) From Discontinued Operations
Key Statistics:
Daily Production
Liquids (Bbl)
Natural Gas (Mcf)
Average Realized Price
Liquids ($/Bbl)
Natural Gas ($/Mcf)
2003
Year ended December 31,
2002
2001
$
106,339 $
91,576 $
154,873
59,171
27,731
28,762
115,664
(9,325)
(3,264)
(6,061) $
28,468
48,405
76,873
14,703
5,146
9,557 $
4,106
32,823
4,923
46,615
27.71 $
5.41 $
22.57 $
3.00 $
$
$
$
29,893
50,500
80,393
74,480
26,068
48,412
5,688
66,812
22.55
4.43
The long−term debt of the Company is recorded at the consolidated level and is not reflected by each component. Thus, the Company
has not allocated interest expense to the discontinued operations.
FUTURE TRENDS
The Company expects crude oil and natural gas production from continuing operations to increase in 2004 and 2005 compared to 2003
assuming commodity prices stay in the range experienced in 2003. The increased production in 2004 is expected primarily from
ramp−up of the Phase 2A expansion of the Alba field in Equatorial Guinea and the initial sales from the Mari−B field, offshore Israel.
The increase in 2005 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 2004 capital expenditures budget at approximately $459.7 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.
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.
38
Impact of Recently Issued Accounting Pronouncements
In December 2003, the SEC issued Staff Accounting Bulletin (“SAB”) No. 104, “Revenue Recognition.” This SAB revises or rescinds
portions of the revenue recognition interpretive guidance included in the SAB codification to make it consistent with current
authoritative accounting guidance. The principal revisions relate to revenue recognition guidance no longer necessary due to
developments in U.S. generally accepted accounting principles. The pronouncement had no impact on the Company’s historical
financial statements.
During 2003, the Financial Accounting Standards Board (“FASB”) issued several new pronouncements:
SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” amends and clarifies financial
accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for
hedging activities that fall within the scope of SFAS No. 133. SFAS No. 149 is effective for contracts entered into or modified after
June 30, 2003, with certain exceptions, and for hedging relationships designated after June 30, 2003. The adoption of this statement
had no impact on the Company’s historical financial statements.
SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity,” establishes
standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It
requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). Many of
those instruments were previously classified as equity. During the second quarter of 2003, the Company adopted SFAS No. 150. As a
result, the Company recorded an additional 1.04 million shares of treasury stock at a cost of $36.6 million and an obligation of $36.6
million.
SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits − An Amendment of FASB
Statements No. 87, 88 and 106,” revises employers’ disclosures about pension plans and other postretirement benefit plans and
requires additional disclosures about the assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans
and other defined benefit postretirement plans. Most of the requirements are effective for financial statements with fiscal years ending
after December 15, 2003. The Company has made additional disclosures in its 2003 financial statements in compliance with SFAS
No. 132.
FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities, an Interpretation of Accounting
Research Bulletin No. 51,” addresses consolidation by business enterprises of variable interest entities. This Interpretation requires
existing unconsolidated variable interest entities to be consolidated by their primary beneficiaries if the entities do not effectively
disperse risks among parties involved. Special provisions apply to enterprises that have fully or partially applied Interpretation No. 46
prior to issuance of this revised Interpretation. Otherwise, application of this Interpretation is required in financial statements of public
entities that have interests in variable interest entities or potential variable interest entities commonly referred to as special−purpose
entities for periods ending after December 15, 2003. Application by public entities for all other types of entities is required in financial
statements for periods ending after March 15, 2004. The provisions of this Interpretation would be applied if the Company were to
acquire an interest in a variable interest entity. The adoption of this statement had no impact on the Company’s historical financial
statements.
In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“the Act”) became law. The Act
introduces a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that
provide a benefit that is at least actuarially equivalent to Medicare. FASB Staff Position 106−1, “Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” allows deferral of the
recognition of the Act’s provisions until authoritative guidance on the accounting for the federal subsidy is issued. The Company has
elected to defer recognition of the effects of the Act in the accounting for and disclosure of its postretirement benefit plan in
accordance with the Staff Position. Authoritative guidance on accounting for the federal subsidy is pending. Final guidance could
require the Company to change previously reported information. The Company does not believe that the effects of the Act will have a
material adverse impact on its financial condition or results of operations.
39
Accounting for Costs Associated with Mineral Rights
During 2003, a reporting issue arose regarding the application of certain provisions of SFAS No. 141, “Business Combinations,” and
SFAS No. 142, “Goodwill and Other Intangible Assets,” to companies in the extractive industries, including oil and gas companies.
The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights associated with extracting crude oil and
natural gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific
footnote disclosures. The EITF has added the treatment of oil and gas mineral rights to an upcoming agenda, which may result in a
change in how Noble Energy classifies these assets. Historically, the Company has included the costs of mineral rights associated with
extracting crude oil and natural gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 142 requires
oil and gas companies to classify costs of mineral rights associated with extracting crude oil and natural gas as a separate intangible
assets line item on the balance sheet, net of amortization, the Company most likely would be required to reclassify certain amounts out
of oil and gas properties and into a separate intangible assets line item. The Company’s cash flows and results of operations would not
be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with existing
successful efforts accounting rules.
If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights associated with
extracting crude oil and natural gas as a separate intangible assets line item on the balance sheet, Noble Energy would be required to
reclassify the estimated amounts as follows:
Intangible Assets (in thousands)
Proved leasehold acquisition costs
Unproved leasehold acquisition costs
Total leasehold acquisition costs
Less: accumulated depletion
Net leasehold acquisition costs
December 31,
2003
835,738 $
127,194
962,932
(496,227)
466,705 $
2002
1,083,103
153,789
1,236,892
(554,932)
681,960
$
$
Further, the Company does not believe the classification of the costs of mineral rights associated with extracting oil and gas as
intangible assets would have any impact on compliance with covenants under the Company’s debt agreements.
Item 7a. Quantitative and Qualitative Disclosures About Market Risk.
Cash Flow Hedges – The Company, from time to time, uses various derivative instruments in connection with anticipated crude oil
and natural gas sales to minimize the impact of product price fluctuations. Such instruments include fixed price hedges, variable to
fixed price swaps, costless collars and other contractual arrangements. Although these derivative instruments expose the Company to
credit risk, the Company takes reasonable steps to protect itself from nonperformance by its counterparties including periodic
assessment of necessary provisions for bad debt allowance; however, the Company is not able to predict sudden changes in its
counterparties’ creditworthiness. The Company accounts for its derivative instruments under SFAS No. 133, “Accounting for
Derivative Instruments and Hedging Activities,” as amended, and has elected to designate its derivative financial instruments as cash
flow hedges. Derivative financial instruments designated as cash flow hedges are reflected at fair value on the Company’s
consolidated balance sheets. Changes in fair value, to the extent the hedge is effective, are reported in AOCI until the forecasted
transaction occurs. Gains and losses from such derivatives related to the Company’s crude oil and natural gas production and which
qualify for hedge accounting treatment are recorded in oil and gas sales and royalties on the Company’s consolidated statements of
operations upon sale of the associated products. Hedge effectiveness is assessed at least quarterly based on total changes in the
derivative instrument’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized
immediately in other income.
40
During 2003, 2002 and 2001, the Company entered into various crude oil and natural gas fixed price swaps, costless collars and
costless collar combinations related to its crude oil and natural gas production. The tables below depict the various transactions.
Natural Gas
Hedge MMBTUpd
Fixed price range
Floor price range
Ceiling price range
Percent of daily production
Gain (loss) per Mcf
Crude Oil
Hedge Bpd
Fixed price
Floor price range
Ceiling price range
Percent of daily production
Gain (loss) per Bbl
2003
190,038
2002
170,274
$3.25 − $3.80
$4.00 − $5.25
$2.00 − $3.50
$2.45 − $5.10
$
56%
(.44) $
50%
.05
$
2001
16,947
$5.23 − $5.41
$3.25 − $5.00
$4.60 − $6.25
5%
.04
2003
15,793
2002
5,247
2001
126
27.81
$
$23.00 − $27.00
$27.20 − $35.05
$23.00 − $24.00
$29.30 − $30.10
$
44%
(1.01)
$
18%
(.02)
$
.5%
.01
During 2003, 2002 and 2001, the Company included a reduction of $67.5 million and gains of $5.9 million and $5.1 million,
respectively, related to its cash flow hedges in oil and gas sales and royalties. During 2003, 2002 and 2001, no gains or losses were
reclassified into earnings as a result of the discontinuance of hedge accounting treatment. During 2003, the Company recorded $.5
million of ineffectiveness related to its cash flow hedges. No ineffectiveness was recorded for 2002 and 2001.
In 2001, the Company only had financial derivatives in the fourth quarter. Of these fourth quarter derivatives, 25,000 MMBTU of
natural gas per day was terminated early. Amounts in AOCI were reclassified into earnings in the same periods during which the
hedged forecasted transaction affected earnings, resulting in an increase in oil and gas sales and royalties of $6.3 million during the
fourth quarter of 2001. As a result, the Company recognized an additional $.70 per MMBTU on the 25,000 MMBTU of natural gas
per day in 2001.
As of December 31, 2003, 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:
Production
Period
1Q 2004
2Q 2004
3Q 2004
4Q 2004
Natural Gas
Crude Oil
MMBTUpd
Price
Per MMBTU
Floor − Ceiling
Bopd
Price
Per Bbl
Floor − Ceiling
120,000
$4.81 − $7.77
120,000
$4.06 − $5.95
120,000
$4.19 − $5.99
120,000
$4.19 − $6.42
15,000
15,000
15,000
5,000
$25.33 −
$31.53
$24.83 −
$31.22
$25.00 −
$31.13
$24.00 −
$30.00
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 ceiling price in respect of each calculation period. The amount payable by the fixed price payor, if
the floating price is below the
41
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.
Accumulated Other Comprehensive Income (Loss) – As of December 31, 2003 and 2002, the balance in AOCI included net deferred
losses of $7.6 million and $14.6 million, respectively, related to crude oil and natural gas derivative instruments accounted for as cash
flow hedges. The net deferred losses are net of deferred income tax benefit of $4.1 million and $7.9 million, respectively.
If commodity prices were to stay the same as they were at December 31, 2003, approximately $11.2 million of deferred losses related
to the fair values of crude oil and natural gas derivative instruments included in AOCI at December 31, 2003 would be reclassified to
earnings during the next twelve months as the forecasted transactions occur, and would be recorded as a reduction in oil and gas sales
and royalties. Any actual increase or decrease in revenues will depend upon market conditions over the period during which the
forecasted transactions occur. All forecasted transactions currently being hedged with crude oil and natural gas derivative instruments
designated as cash flow hedges are expected to occur by December 2004.
Other Derivative Instruments – In addition to the derivative instruments pertaining to the Company’s production as described above,
NEMI, from time to time, employs various derivative instruments in connection with its purchases and sales of third−party production
to lock in profits or limit exposure to natural 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.
NEMI records gains and losses on derivative instruments using mark−to−market accounting. Under this accounting method, the
changes in the market value of outstanding financial instruments are recognized as gains or losses in the period of change. NEMI
recorded a loss of $.2 million, a gain of $.9 million and a loss of $.5 million in GMP proceeds during 2003, 2002 and 2001,
respectively, related to derivative instruments.
Receivables/Payables Related to Crude Oil and Natural Gas Derivative Financial Instruments – At December 31, 2003, the
Company’s consolidated balance sheet included a receivable of $56.1 million and a payable of $67.6 million related to crude oil and
natural gas derivative financial instruments. At December 31, 2002, the Company’s consolidated balance sheet included a receivable
of $10.3 million and a payable of $32.3 million related to crude oil and natural gas derivative financial instruments.
During 2003, the Company had contracts with Enron North America Corporation (“ENA”) that resulted in gains of $6.9 million (net
of allowance) included in GMP proceeds. In addition, as of December 31, 2003, the Company had NYMEX−related transactions with
ENA totaling 149 contracts with a mark−to−market receivable value of $1.8 million.
Interest Rate Lock – The Company occasionally enters into forward contracts or swap agreements to hedge exposure to interest rate
risk. Changes in fair value of interest rate swaps or interest rate “locks” used as cash flow hedges are reported in AOCI, to the extent
the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense. At
December 31, 2003, the Company’s consolidated balance sheet included a payable of $4.0 million related to an outstanding interest
rate lock. The amount of deferred loss included in AOCI at December 31, 2003 was $2.6 million, net of tax.
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, 2003, there was $140 million borrowed against this credit agreement with
an interest rate of 2.19 percent and a maturity date of November 30, 2006. A 10 percent change in the December 31, 2003 interest rate
on this $140 million would result in a change in interest expense of $.3 million.
42
The Company has a new $300 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 62.5 to 150 basis points depending
upon the percentage of utilization and credit rating. At December 31, 2003, there was $190 million borrowed against this credit
agreement with an interest rate of 2.09 percent and a final maturity date of October 28, 2005. A 10 percent change in the
December 31, 2003 interest rate on this $190 million would result in a change in interest expense of $.4 million. 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.
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 statements of operations. However, certain sales transactions 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
43
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 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. 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
44
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.
Item 8. Financial Statements and Supplementary Data.
45
INDEX TO FINANCIAL STATEMENTS
Consolidated Financial Statements of Noble Energy, Inc.
Independent Auditors’ Report
Consolidated Balance Sheets as of December 31, 2003 and 2002
Consolidated Statements of Operations for each of the three years in the period ended December 31, 2003
Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2003
Consolidated Statements of Shareholders’ Equity and Other Comprehensive Income for each of the three
years in the period ended December 31, 2003
Notes to Consolidated Financial Statements
Supplemental Oil and Gas Information (Unaudited)
Supplemental Quarterly Financial Information (Unaudited)
Independent Auditors’ Report on Consolidated Financial Statement Schedule
Schedule II – Valuation and Qualifying Accounts
Financial Statements of Atlantic Methanol Production Company, LLC
Report of Independent Auditors
Balance Sheet as of December 31, 2003 and 2002
Statement of Operations for each of the three years in the period ended December 31, 2003
Statement of Members’ Equity for each of the three years in the period ended December 31, 2003
Statement of Cash Flows for each of the three years in the period ended December 31, 2003
Notes to Financial Statements
46
To the Shareholders and Board of Directors of Noble Energy, Inc.:
Independent Auditors’ Report
We have audited the accompanying consolidated balance sheets of Noble Energy, Inc. (a Delaware corporation) and subsidiaries as of
December 31, 2003 and 2002, and the related consolidated statements of operations, shareholders’ equity and other comprehensive
income, and cash flows for each of the years in the three−year period ended December 31, 2003. 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 audits.
We conducted our audits 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 audits provide 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, 2003 and 2002, and the results of their operations and their cash flows for
each of the years in the three−year period ended December 31, 2003, in conformity with accounting principles generally accepted in
the United States of America.
As discussed in Note 1 to the consolidated financial statements, effective January 1, 2003, the Company changed its method of
accounting for asset retirement obligations.
Houston, Texas
February 26, 2004
KPMG LLP
47
CONSOLIDATED BALANCE SHEETS
NOBLE ENERGY, INC. AND SUBSIDIARIES
(in thousands, except share amounts)
ASSETS
Current Assets:
Cash and cash equivalents
Accounts receivable − trade, net
Derivative financial instruments
Materials and supplies inventories
Other current assets
Assets held for sale
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 Subsidiaries
Other Assets
Total Assets
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Accounts payable − trade
Current installments of long−term debt
Derivative financial instruments
Other current liabilities
Income taxes − current
Total current liabilities
Deferred Income Taxes
Asset Retirement Obligation
Other Deferred Credits and Noncurrent Liabilities
Long−term Debt
Commitments and Contingencies
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; 60,744,583 and
59,868,067 shares issued in 2003 and 2002, respectively
Capital in excess of par value
Accumulated other comprehensive loss
Retained earnings
$
$
$
December 31,
2003
2002
$
$
$
62,374
303,822
56,058
11,083
23,805
21,245
478,387
3,875,598
49,389
3,924,987
(1,825,246)
2,099,741
227,669
36,852
2,842,649
388,428
153,674
67,562
38,506
6,548
654,718
163,146
124,537
50,654
776,021
15,442
232,924
10,271
10,663
41,074
310,374
4,285,508
48,507
4,334,015
(2,194,230)
2,139,785
234,668
45,188
2,730,015
351,856
41,919
32,285
36,159
9,535
471,754
201,939
69,820
977,116
202,480
431,208
(10,886)
526,727
1,149,529
199,558
405,271
(14,603)
458,490
1,048,716
Less common stock in treasury at cost (December 31, 2003, 3,549,976 shares and
December 31, 2002, 2,505,522 shares)
Total shareholders’ equity
Total Liabilities and Shareholders’ Equity
(75,956)
1,073,573
2,842,649
$
(39,330)
1,009,386
2,730,015
$
See accompanying Notes to Consolidated Financial Statements.
48
CONSOLIDATED STATEMENTS OF OPERATIONS
NOBLE ENERGY, INC. AND SUBSIDIARIES
(in thousands, except per share amounts)
Revenues:
Oil and gas sales and royalties
Gathering, marketing and processing
Electricity sales
Income from investment in unconsolidated subsidiaries
Other income
Total Revenues
Costs and Expenses:
Oil and gas operations
Transportation
Oil and gas exploration
Gathering, marketing and processing
Electricity generation
Depreciation, depletion and amortization
Impairment of operating assets
Selling, general and administrative
Accretion of asset retirement obligation
Interest
Interest capitalized
Total Costs and Expenses
Income Before Taxes
Income Tax Provision:
Current
Deferred
Total Tax Provision
Income From Continuing Operations
Discontinued Operations, Net of Tax
Cumulative Effect of Change in Accounting Principle, Net of
Tax
Net Income
Basic Earnings (Loss) Per Share:
Income from continuing operations
Discontinued operations, net of tax
Cumulative effect of change in accounting principle, net of tax
Net Income
Diluted Earnings (Loss) Per Share:
Income from continuing operations
Discontinued operations, net of tax
Cumulative effect of change in accounting principle, net of tax
Net Income
Weighted Average Shares Outstanding:
Basic
Diluted
$
$
$
$
$
$
$
$
$
$
See accompanying Notes to Consolidated Financial Statements.
49
2003
Year ended December 31,
2002
2001
$
839,144
68,158
58,022
40,626
5,036
1,010,986
145,836
14,679
148,818
59,114
50,846
309,343
31,937
52,466
9,331
61,111
(14,134)
869,347
141,639
42,975
8,772
51,747
89,892
(6,061)
(5,839)
77,992
$
1.58
$
(0.11) $
(0.10) $
$
1.37
$
1.56
(0.10) $
(0.10) $
$
1.36
56,964
57,539
609,026
64,517
18,257
9,532
1,246
702,578
105,358
16,441
150,701
53,982
15,946
236,881
47,664
64,040
(16,331)
674,682
27,896
2,479
17,322
19,801
8,095
9,557
17,652
0.14
0.17
0.31
0.14
0.17
0.31
$
$
$
$
$
$
$
$
$
$
716,939
64,640
6,981
953
789,513
103,656
16,012
152,096
51,932
233,516
44,164
53,960
(15,953)
639,383
150,130
5,527
59,440
64,967
85,163
48,412
133,575
1.51
0.85
2.36
1.49
0.84
2.33
57,196
57,763
56,549
57,303
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
Non−cash effect of discontinued operations
Cumulative effect of change in accounting principle, net of tax
(Gain) loss on disposal of assets
Deferred income taxes
Accretion of asset retirement obligation
Income from unconsolidated subsidiaries
Dividends received from unconsolidated subsidiary
Impairment of operating assets
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 subsidiaries
Proceeds from sale of property, plant and equipment
Distribution from unconsolidated subsidiaries
Aspect acquisition, net of cash acquired
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 note payable obtained in Aspect acquisition
Repayment of treasury stock obligation
Net Cash (Used in) Provided by Financing Activities
Increase (Decrease) in Cash and Cash Equivalents
Cash and Cash Equivalents at Beginning of Year
Cash and Cash Equivalents 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:
Treasury stock and note obligation
Issuance of treasury stock for acquisition
Debt assumed in acquisition
See accompanying Notes to Consolidated Financial Statements.
50
2003
Year ended December 31,
2002
2001
$
77,992
$
17,652
$
133,575
309,343
27,116
63,637
33,380
87,933
5,839
17,978
(31,475)
9,331
(40,626)
46,125
31,937
(19,166)
8,336
(70,898)
16,849
36,572
(7,433)
602,770
(527,386)
81,084
1,500
236,881
8,458
81,396
21,254
48,405
(106)
20,856
(9,532)
17,696
(5,810)
10,942
(49,945)
21,972
81,764
5,072
506,955
(595,739)
(7,652)
20,363
5,500
(444,802)
(577,528)
24,685
(9,755)
135,435
(221,195)
(3,580)
(36,626)
(111,036)
46,932
15,442
62,374
31,824
51,147
36,626
$
$
$
$
$
$
$
7,692
(9,147)
158,669
(124,929)
(19,507)
12,778
(57,795)
73,237
15,442
$
31,303
$
(40,394) $
$
$
233,516
99,684
17,213
50,500
(2,098)
63,604
(6,981)
13,990
(2,224)
57,973
(64,951)
(17,960)
52,313
628,154
(738,706)
(36,641)
1,434
(97,792)
(871,705)
12,283
(9,042)
675,000
(375,000)
(9,605)
293,636
50,085
23,152
73,237
25,745
66,131
14,238
40,043
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND
OTHER COMPREHENSIVE INCOME
NOBLE ENERGY, INC. AND SUBSIDIARIES
(in thousands, except
common stock)
Comprehensive
Income (Loss)
Shares Issued
Amount
Common Stock
Capital in
Excess of
Par Value
Accumulated
Other
Comprehensive
Income (Loss)
Retained
Earnings
$
133,575
59,002,162 $ 196,672 $
373,259 $ 325,452
133,575
Treasury
Stock
At Cost
Total
Shareholders’
Equity
$
(45,701) $
849,682
133,575
December 31, 2000
Net Income
Change in fair value of cash
flow hedges, net of income
tax
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 $.5
income tax
Change in fair value of cash
flow hedges, net of income
tax
Change in additional
minimum liability and
other, net of tax
Exercise of stock options
Cash dividends ($.16 per
share)
Total
December 31, 2002
Net Income
Change in fair value of cash
flow hedges, net of income
tax
Change in additional
minimum liability and
other, net of tax
Exercise of stock options
Cash dividends ($.17 per
share)
Treasury stock purchase
Total
December 31, 2003
$
$
$
$
5,070
138,645
17,652
1
(19,769)
95
(2,021)
77,992
2,324
1,393
509,161
1,697
7,867
14,978
(9,042)
5,070
6,371
59,511,323 $ 198,369 $
396,104 $ 449,985 $
5,070 $
(39,330) $
17,652
5,070
14,238
16,675
(9,042)
1,010,198
17,652
1
1
(19,769)
(19,769)
356,744
1,189
9,167
95
(9,147)
59,868,067 $ 199,558 $
405,271 $ 458,490 $
(14,603) $
(39,330) $
77,992
2,324
1,393
876,516
2,922
25,937
(9,755)
(36,626)
95
10,356
(9,147)
1,009,386
77,992
2,324
1,393
28,859
(9,755)
(36,626)
$
81,709
60,744,583 $ 202,480 $
431,208 $ 526,727 $
(10,886) $
(75,956) $
1,073,573
See accompanying Notes to Consolidated Financial Statements.
51
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 its subsidiaries conform to accounting principles generally accepted in the United
States of America. The more significant of such policies are 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”). All significant intercompany balances and transactions have been
eliminated upon consolidation.
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 and Texas); the Mid−Continent Region (Oklahoma and Kansas); and the Rocky
Mountain Region (Colorado, Montana, Nevada, Wyoming and California). The international areas of operations include Argentina,
China, Ecuador, Equatorial Guinea, the Mediterranean Sea (Israel), the North Sea (Denmark, the Netherlands and the 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 crude oil and natural gas reserves. The accuracy of any reserve
estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result,
reserve estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered. Noble Energy has
engaged independent third−party reserve engineers to perform an audit of the Company’s procedures and methods used to estimate
proved reserves for each of the three years 2001−2003. The audit for 2003 included a review of the areas representing 80 percent of
the Company’s reserves. In addition, Noble Energy has obtained independent third−party estimates for several major international
properties including those in Ecuador, Equatorial Guinea and Israel. Other items subject to estimates and assumptions include the
carrying amount of property, plant and equipment; asset retirement obligations; valuation allowances for receivables 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.
The SEC requested clarification, which the Company provided, as to the Company’s Israel and Equatorial Guinea gas reserves
recorded in excess of existing contract amounts. SEC guidelines do not limit reserve bookings only to contracted volumes if it can be
demonstrated that there is reasonable certainty that a market exists, which the Company believes exists in both of these situations. The
Israel gas contract is for a period of 11 years. The Israel gas market, as estimated by the Israeli Ministry of National Infrastructure,
from 2005 to 2020, is twenty times greater than Noble Energy’s uncontracted net
52
estimated proved reserves. In Equatorial Guinea, the gas contract, which runs through 2026, is between the field owners and the
methanol plant owners. Noble Energy, through its subsidiaries, holds a working interest in the field as well as an interest in the
methanol plant. The Company has recorded reserves through the end of the concession’s term in 2040. Noble Energy has obtained
independent third−party engineer reserve estimates for both of these projects.
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 statements 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. The total asset retirement obligations of $199.3 million consist of
$175.9 million for the United States and $23.4 million for the North Sea and are included in future production and development costs
for purposes of 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.
In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long−Lived Assets,” the Company reviews oil and
gas properties and other long−lived assets for impairment when events and circumstances indicate a decline in the recoverability of the
carrying value of such properties, such as a downward revision of the reserve estimates or commodity prices. The Company estimates
the future cash flows expected in connection with the properties and compares such future cash flows to the carrying amount of the
properties to determine if the carrying amount is recoverable. When the carrying amounts of the properties exceed their estimated
undiscounted future cash flows, the carrying amount of the properties is written down to their fair value as determined by discounting
its estimated future cash flows. The factors used to determine fair value include, but are not limited to, estimates of proved reserves,
future commodity prices, and timing of future production, future capital expenditures and a discount rate commensurate with the
risk−free interest rate reflective of the lives remaining for the respective oil and gas properties.
The Company recognized $31.9 million of impairments in 2003, primarily related to a reserve revision on the East Cameron 338 field
in the Gulf of Mexico after recompletion and remediation activities produced less−than−expected results. An analysis of the
performance response of the field resulted in a reduction in proved reserves of 2.2 MMBoe (unaudited).
53
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 cash equivalents include cash on hand and investments purchased with original
maturities of three months or less.
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:
(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
2003
2002
2001
Income
(Numerator)
$77,992
Shares
(Denominator)
56,964
Income
(Numerator)
$17,652
Shares
(Denominator)
57,196
Income
(Numerator)
$133,575
Shares
(Denominator)
56,549
$1.37
$.31
$2.36
$77,992
56,964
$17,652
57,196
$133,575
$77,992
$1.36
575
57,539
$17,652
$.31
567
57,763
$133,575
$2.33
56,549
754
57,303
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
2003
1,533,290
$37.63 − $43.21
$41.10
2002
2,229,978
$35.40 − $43.21
$39.77
2001
1,485,303
$38.88 − $43.21
$41.29
54
Accounting for Employee Stock−Based Compensation
At December 31, 2003, the Company had 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 Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to
Employees,” and related Interpretations. At issuance, no 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 benefit
Deduct: Total stock−based employee compensation expense determined
under fair value based method for all awards, net of related tax benefit
Pro forma net income
Earnings per share:
Basic − as reported
Basic − pro forma
Diluted − as reported
Diluted − pro forma
$
$
$
$
$
$
2003
2002
77,992
153
(10,022)
68,123
1.37
1.20
1.36
1.18
$
$
$
$
$
$
17,652
418
(9,934)
8,136
.31
.14
.31
.14
$
$
$
$
$
$
2001
133,575
(8,248)
125,327
2.36
2.22
2.33
2.19
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 2003, 2002 and 2001, respectively, as follows:
(amounts expressed in percentages)
Interest rate
Dividend yield
Expected volatility
Expected life (in years)
2003
2002
2001
5.07
.38
28.38
9.42
4.78
.43
40.26
9.73
5.46
.40
38.19
9.64
The weighted average fair value of options granted using the Black−Scholes option pricing model for 2003, 2002 and 2001,
respectively, is as follows:
Black−Scholes model weighted average fair value option price
$
16.64
$
18.14
$
23.86
2003
2002
2001
Revenue Recognition and Gas Imbalances
The Company records revenues from the sales of crude oil, natural gas and methanol when the product is delivered at a fixed or
determinable price, title has transferred and collectibility is reasonably assured.
When the Company has an interest with other producers in certain properties from which crude oil or natural gas is produced, the
Company uses the entitlements method to account for any imbalances. Imbalances occur when the Company sells more or less product
than it is entitled to under its ownership percentage. Revenue is recognized only on the entitlement percentage of volumes sold. Any
amount sold by the Company in excess of its entitlement is treated as a
55
liability. Any amount sold by the Company less than its entitlement is treated as a receivable. The Company records the non−current
portion of the liability in other deferred credits and non−current liabilities, and the current portion of the liability in other current
liabilities. The Company records the non−current portion of the receivable in other assets and the current portion of the receivable in
other current assets. The Company’s natural gas imbalance liabilities were $17.0 million and $15.4 million at December 31, 2003 and
2002, respectively. The Company’s imbalance receivables were $22.2 million and $20.1 million at December 31, 2003 and 2002,
respectively, and are valued at the amount that is expected to be received.
Revenues derived from electricity generation are recognized when power is transmitted or delivered, the price is fixed and
determinable and collectibility is reasonably assured.
NEMI records third−party sales, net of cost of goods sold, as GMP when the product is delivered at a fixed or determinable price, title
has transferred and collectibility is reasonably assured.
Derivative Financial Instruments and Hedging Activities
The Company, from time to time, uses various derivative instruments in connection with anticipated crude oil and natural gas sales to
minimize the impact of product price fluctuations. Such instruments include fixed price hedges, variable to fixed price swaps, costless
collars and other contractual arrangements. Although these derivative instruments 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 on 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 AOCI 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 on the statements 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, 2003, the Company recorded crude
oil and natural gas hedge receivables and liabilities of $56.1 million and $67.6 million, respectively, and other comprehensive loss, net
of tax, of $7.6 million related to the Company’s derivative 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 Subsidiaries
Through its ownership in AMCCO, the Company owns a 45 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−2 senior secured notes
due December 15, 2004 to fund construction payments owed in connection with the construction of its methanol plant. The
Company’s investment in the methanol plant is included in investment in unconsolidated subsidiaries. The $125 million Series A−2
notes are in current installments of long−term debt on the Company’s balance sheet.
56
The plant construction started during 1998 and initial production of commercial grade methanol commenced May 2, 2001. 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 of natural gas from the 34 percent−owned Alba field. The methanol plant has a contract
through 2026 to purchase natural gas from the Alba field. For more information, see “Note 9 − Unconsolidated Subsidiaries” of this
Form 10−K.
Electricity Generation − Ecuador Integrated Power Project
The Company, through its subsidiaries, EDC Ecuador Ltd. and MachalaPower Cia. Ltda., has a 100 percent ownership interest in an
integrated gas−to−power project. The project includes the Amistad natural gas field, offshore Ecuador, which supplies fuel to the
Machala power plant located in Machala, Ecuador. The revenues attributable to the gas−to−power project are reported in “Electricity
Sales” and the expenses are reported as “Electricity Generation.”
Cumulative Effect of Change in Accounting Principle
On January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” and recorded a non−cash
charge of $9.0 million ($5.8 million, net of tax) as the cumulative effect of change in accounting principle.
Reclassification
Certain reclassifications have been made to the 2002 and 2001 consolidated financial statements to conform to the 2003 presentation.
These reclassifications are not material to the Company’s financial position.
Recently Issued Pronouncements
In December 2003, the SEC issued SAB No. 104, “Revenue Recognition.” This SAB revises or rescinds portions of the revenue
recognition interpretive guidance included in the SAB codification to make it consistent with current authoritative accounting
guidance. The principal revisions relate to revenue recognition guidance no longer necessary due to developments in U.S. generally
accepted accounting principles. The pronouncement had no impact on the Company’s historical financial statements.
SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits − An Amendment of FASB
Statements No. 87, 88 and 106,” revises employers’ disclosures about pension plans and other postretirement benefit plans and
requires additional disclosures about the assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans
and other defined benefit postretirement plans. Most of the requirements are effective for financial statements with fiscal years ending
after December 15, 2003. For more information, see “Item 8. Financial Statements and Supplementary Data—Note 6 − Employee
Benefit Plans” of this Form 10−K. The Company has made additional disclosures in its 2003 financial statements in compliance with
SFAS No. 132.
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’s
asset retirement obligations consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities
associated with its oil and gas properties. The Company adopted SFAS No. 143 on January 1, 2003 and, as of December 31, 2003,
recorded as the fair value of asset retirement obligations, $109.4 million related to the United States and $15.1 million related to the
North Sea. The Company recognized, as the cumulative effect of adoption of this standard, a non−cash pre−tax charge of $9.0 million
in 2003. The expected future retirement obligation for the United States is $175.9 million and for the North Sea is $23.4 million. The
difference between the expected future retirement obligation and the fair value of the retirement obligation
57
will be expensed beginning in 2003 based on the credit−adjusted risk−free rate of 8.5 percent until the asset retirement date.
Below is a reconciliation of the beginning and ending aggregate carrying amount of the Company’s asset retirement obligations:
(dollars in thousands)
Beginning of the period
Initial adoption entry
Liabilities incurred in the current period
Liabilities settled in the current period
Accretion expense
End of the period
Twelve Months Ended
December 31, 2003
109,821
18,680
(13,295)
9,331
124,537
$
$
The following table summarizes the pro forma net income and earnings per share, as of December 31, for each of the years, for the
change in accounting had it been implemented on January 1, 2001 (in thousands, except per share amounts):
Net income
Net income per share, basic
Net income per share, diluted
2002
2001
As Reported
Pro Forma
As Reported
Pro Forma
$
$
$
17,652
.31
.31
$
$
$
8,556
.15
.15
$
$
$
133,575
2.36
2.33
$
$
$
124,770
2.21
2.18
In addition, on a pro forma basis as required by SFAS No. 143, if the Company had applied the provisions of SFAS No. 143 as of
January 1, 2001, the amount of asset retirement obligations would have been $99.7 million.
SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” amends and clarifies financial
accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for
hedging activities that fall within the scope of SFAS No. 133. SFAS No. 149 is effective for contracts entered into or modified after
June 30, 2003, with certain exceptions, and for hedging relationships designated after June 30, 2003. The adoption of this statement
had no impact on the Company’s historical financial statements.
SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity,” establishes
standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It
requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). Many of
those instruments were previously classified as equity. During the second quarter of 2003, the Company adopted SFAS No. 150. As a
result, the Company recorded an additional 1,044,454 shares of treasury stock at a cost of $36.6 million and an obligation of $36.6
million. For more information, see “Item 8. Financial Statements and Supplementary Data—Note 12 − Company Stock Repurchase
Forward Program” of this Form 10−K.
FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities, an Interpretation of Accounting
Research Bulletin No. 51,” addresses consolidation by business enterprises of variable interest entities. This Interpretation requires
existing unconsolidated variable interest entities to be consolidated by their primary beneficiaries if the entities do not effectively
disperse risks among parties involved. Special provisions apply to enterprises that have fully or partially applied Interpretation No. 46
prior to issuance of this revised Interpretation. Otherwise, application of this Interpretation is required in financial statements of public
entities that have interests in variable interest entities or potential variable interest entities commonly referred to as special−purpose
entities for periods ending after December 15, 2003. Application by public entities for all other types of entities is required in financial
statements for periods ending after March 15, 2004. The provisions of this Interpretation would be applied if
58
the Company were to acquire an interest in a variable interest entity. The adoption of this statement had no impact on the Company’s
historical financial statements.
In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“the Act”) became law. The Act
introduces a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that
provide a benefit that is at least actuarially equivalent to Medicare. FASB Staff Position 106−1, “Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” allows deferral of the
recognition of the Act’s provisions until authoritative guidance on the accounting for the federal subsidy is issued. The Company has
elected to defer recognition of the effects of the Act in the accounting for and disclosure of its postretirement benefit plan in
accordance with the Staff Position. Authoritative guidance on accounting for the federal subsidy is pending. Final guidance could
require the Company to change previously reported information. The Company does not believe that the effects of the Act will have a
material impact on its financial condition or results of operations.
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 energy trading activities, the EITF has expanded its definition of
energy trading activities to include the marketing activities in which the Company is engaged. The Company has reclassified its
statements of operations for all periods to present its GMP activities on a net rather than a gross basis. The adoption of EITF 02−03
resulted in a decrease in revenues and a decrease in operating expenses of $649.6 million and $656.4 million for the years ended
December 31, 2002 and 2001, respectively. The adoption of EITF 02−03 had no effect on operating income or cash flow.
Accounting for Costs Associated with Mineral Rights
During 2003, a reporting issue arose regarding the application of certain provisions of SFAS No. 141, “Business Combinations,” and
SFAS No. 142, “Goodwill and Other Intangible Assets,” to companies in the extractive industries, including oil and gas companies.
The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights associated with extracting crude oil and
natural gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific
footnote disclosures. The EITF has added the treatment of oil and gas mineral rights to an upcoming agenda, which may result in a
change in how Noble Energy classifies these assets. Historically, the Company has included the costs of mineral rights associated with
extracting crude oil and natural gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 142 requires
oil and gas companies to classify costs of mineral rights associated with extracting crude oil and natural gas as a separate intangible
assets line item on the balance sheet, net of amortization, the Company most likely would be required to reclassify certain amounts out
of oil and gas properties and into a separate intangible assets line item. The Company’s cash flows and results of operations would not
be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with existing
successful efforts accounting rules.
If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights associated with
extracting crude oil and natural gas as a separate intangible assets line item on the balance sheet, Noble Energy would be required to
reclassify the estimated amounts as follows:
Intangible Assets (in thousands)
Proved leasehold acquisition costs
Unproved leasehold acquisition costs
Total leasehold acquisition costs
Less: accumulated depletion
Net leasehold acquisition costs
59
December 31,
2003
835,738
127,194
962,932
(496,227)
466,705
$
$
2002
1,083,103
153,789
1,236,892
(554,932)
681,960
$
$
Further, the Company does not believe the classification of the costs of mineral rights associated with extracting crude oil and natural
gas as intangible assets would have any impact on compliance with covenants under the Company’s debt agreements.
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, Cash Equivalents, 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 Derivative Financial Instruments
The fair value of crude oil and natural gas derivative instruments is the estimated amount the Company would receive or pay to
terminate the agreements at the reporting date taking into account creditworthiness of the counterparties.
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
2003
2002
Carrying
Amount
Fair
Value
Carrying
Amount
Fair
Value
$
$
(11,132) $
(776,021) $
(11,132) $
(836,271) $
(22,520) $
(977,116) $
(22,520)
(991,086)
60
Note 3 − Debt
A summary of debt at December 31 follows:
(in thousands)
$400 million Credit Agreement, maturity date November
2006
$300 million Credit Agreement, maturity date
October 2005
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 2004
Outstanding debt
Less: unamortized discount
current installment of long−term debt
Long−term debt
$
2003
2002
Percentage
Interest
Rate
Debt
Percentage
Interest
Rate
Debt
$
140,000
2.19
$
380,000
190,000
7,928
100,000
250,000
100,000
125,000
20,746
933,674
3,979
153,674
776,021
2.09
6.25
7.25
8.00
7.25
8.95
2.16
11,508
100,000
250,000
100,000
125,000
58,738
1,025,246
6,211
41,919
977,116
$
2.47
6.25
7.25
8.00
7.25
8.95
2.18
The Company’s total long−term debt, net of unamortized discount, at December 31, 2003, was $776.0 million compared to $977.1
million at December 31, 2002. The ratio of debt−to−book capital (defined as the Company’s total debt plus its equity) was 46 percent
at December 31, 2003, compared with 50 percent at December 31, 2002.
The Company entered into a $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, 2003, there was $140 million borrowed against this credit agreement, which has a maturity date of
November 30, 2006.
The Company entered into a new $300 million 364−day credit agreement on November 3, 2003 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, 2003, there was $190 million borrowed against this credit agreement. The agreement has a maturity date of
October 28, 2004 for the revolving commitment and a final maturity date of October 28, 2005 for the term commitment that includes
any balance remaining after the revolving commitment matures.
The current installment of long−term debt totals $153.7 million at December 31, 2003.
During 2004, a subsidiary of the Company borrowed a total of $150 million from certain commercial lending institutions. The interest
rate on the borrowing is LIBOR plus an effective range of 60 to 130 basis points depending on credit rating and the borrowing is for a
term of five years. Proceeds were used to reduce amounts due under the $400 million credit agreement.
Financial covenants on both the $400 million and $300 million credit facilities include the following: (a) the ratio of Earnings Before
Interest, Taxes, Depreciation and Exploration Expense (“EBITDAX”) to 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;
61
(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 entities may not be less than $800 million at any time.
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
Effect of:
State taxes, net of federal benefit
Difference between U.S. and foreign rates
Write−off of Vietnam investment
Other, net
Effective rate
2003
2002
2001
35.0
.4
14.6
(11.5)
(2.0)
36.5
35.0
1.1
36.8
(2.0)
70.9
35.0
.3
7.6
.4
43.3
The net current deferred tax asset in the following table is classified as other current assets on 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:
Accrued expenses
Deferred income
Allowance for doubtful accounts
Mark−to−market − derivative contracts
Net U.S. and State Current Deferred Tax Assets
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
Postretirement 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)
2003
2002
$
1,507
351
2,184
4,102
8,144
(140,760)
4,777
2,848
5,935
8,716
8,169
(235)
(110,550)
(102,406)
(54,809)
16,732
(38,077)
(14,519)
(155,002) $
980
387
353
7,864
9,584
(183,338)
4,777
4,594
5,935
11,940
9,668
(245)
(146,669)
(137,085)
(55,270)
21,148
(34,122)
(21,148)
(192,355)
$
$
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
2003
2002
2001
$
$
56,068
85,571
141,639
$
$
(11,636) $
39,532
27,896
$
166,999
(16,869)
150,130
62
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
Provision including discontinued operations
Income tax provision associated with discontinued operations
Total tax provision
2003
2002
2001
$
$
45,985
(31,087)
1,867
(1,084)
32,341
461
48,483
(3,264)
51,747
$
$
(7,945) $
1,421
895
(212)
14,675
16,113
24,947
5,146
19,801
$
24,743
53,591
651
360
6,200
5,490
91,035
26,068
64,967
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, 2003. 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.
The Company has not recorded U.S. deferred income taxes on the undistributed earnings of its consolidated foreign subsidiaries since
management intends to permanently reinvest those earnings. As of December 31, 2003, the undistributed earnings of the consolidated
foreign subsidiaries were approximately $90.8 million. Upon distribution of these earnings in the form of dividends or otherwise, the
Company may be subject to U.S. income taxes and foreign withholding taxes. It is not practical, however, to estimate the amount of
taxes that may be payable on the eventual remittance of these earnings because of the possible application of U.S. foreign tax credits.
Presently the Company is not claiming foreign tax credits, but it may be in a credit position when any future remittance of foreign
earnings takes place.
The Company recognized deferred tax assets associated with its foreign loss carryforwards. The tax effect of these carryforwards
decreased from $21.1 million in 2002 to $16.7 million in 2003. The valuation allowances associated with those carryforwards
decreased from $21.1 million in 2002 to $14.5 million in 2003. This change was due to the elimination of the carryforward and
offsetting valuation allowance associated with Vietnam, the elimination of the valuation allowance associated with Israel and the
partial elimination of the valuation allowance associated with China. Because of the relatively short carryforward period in China and
the lack of a long−term fixed price contract, the valuation allowance associated with China was not fully eliminated.
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. As of
December 31, 2003, no restricted stock had 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 percent 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 and again in 2003,
63
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
9,250,000 shares. At December 31, 2003, the Company had reserved 6,939,524 shares of common stock for issuance, including
3,218,265 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 calendar 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, 2003, the Company
had reserved 297,571 shares of common stock for issuance, including 49,786 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 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, 2001, 2002 and 2003, and changes during each of
the years then ended, is presented below.
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
Options granted
Options exercised
Options canceled
Outstanding at December 31, 2003
Options Outstanding
Options Exercisable
Number
Outstanding
Exercise
Price
Number
Exercisable
Weighted
Average
Exercise
Price
29.44
42.77
24.97
33.11
32.46
32.66
21.56
37.02
33.38
35.42
28.16
36.96
34.83
2,408,522
$
32.08
2,530,285
$
32.10
2,871,943
$
32.84
2,642,077
$
34.40
$
3,721,105
723,400
$
(509,161) $
(81,267) $
$
3,854,077
732,500
$
(356,744) $
(36,612) $
$
4,193,221
758,900
$
(876,516) $
(106,561) $
$
3,969,044
64
The following table summarizes information about Noble Energy’s stock options which were outstanding, and those which were
exercisable, as of December 31, 2003.
Range of
Exercise Prices
$17.79 − $22.23
$22.23 − $26.68
$26.68 − $31.13
$31.13 − $35.57
$35.57 − $40.02
$40.02 − $44.47
Options Outstanding
Options Exercisable
Number
Outstanding
Weighted
Average
Remaining
Life
Weighted
Average
Exercise
Price
520,788
74,642
103,762
1,333,157
1,051,701
884,994
3,969,044
4.9 Years
1.5 Years
4.0 Years
8.4 Years
3.9 Years
5.1 Years
5.8 Years
$20.06
$24.39
$28.91
$34.06
$38.14
$42.32
$34.83
Number
Exercisable
520,788
74,642
103,762
243,744
1,011,701
687,440
2,642,077
Weighted
Average
Exercise
Price
$20.06
$24.39
$28.91
$32.89
$38.21
$42.10
$34.40
Compensation expense totaling $.2 million and $.6 million was recognized in 2003 and 2002, respectively, due to the accelerated
vesting of stock options as a result of the retirement of certain employees. There was no compensation expense recognized in 2001.
The Company claimed deductions on its 2002 and 2003 federal income tax returns for compensation expense associated with the
exercise of stock options. This increased the Company’s federal income tax refund by $2.0 million for 2002 and decreased its liability
by $3.9 million and $4.0 million for 2003 and 2001, respectively.
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, which provides for restoration of amounts to 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.
65
The Company sponsors other plans for the benefit of its employees and retirees. These plans include health care and life insurance
benefits. The Company uses a December 31 measurement date for its plans. The following table reflects the required disclosures on
the Company’s pension and other postretirement benefit plans at December 31:
$
$
$
$
$
$
$
$
$
(in thousands)
Change in benefit obligation
Benefit obligation at beginning of year
Service cost
Interest cost
Amendments
Plan participants’ contributions
Actuarial 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 assets at end of year
Funded status
Unrecognized net actuarial loss
Unrecognized prior service cost (benefit)
Unrecognized net transition obligation
Accrued benefit costs
Components of net periodic benefit cost
Service cost
Interest cost
Expected return on plan assets
Transition obligation recognition
Amortization of prior service cost
Recognized net actuarial loss
Net periodic benefit cost
Additional Information
Increase in minimum liability included in accumulated
other comprehensive income
Weighted−average assumptions used to determine
benefit obligations at December 31,
Discount rate
Rate of compensation increase
Weighted−average assumptions used to determine
net periodic benefit costs for year ended December
31,
Discount rate
Expected long−term return on plan assets
Rate of compensation increase
Pension Benefits
Other Benefits
2003
2002
2003
2002
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
$
$
94
$
6.75%
4.00%
7.25%
8.50%
4.00%
6,141
534
524
114
2,053
(210)
9,156
$
$
$
210
(210)
$
(9,156) $
4,955
(836)
2,688
346
314
90
2,849
(146)
6,141
146
(146)
(6,141)
2,472
(244)
(5,037) $
(3,913)
534
524
(110)
272
1,220
$
$
$
6.25%
4.00%
6.75%
4.00%
346
314
(30)
73
703
6.75%
4.00%
7.25%
4.00%
106,224
5,271
6,772
196
4,366
(4,559)
118,270
$
$
$
56,660
7,583
14,341
(4,559)
$
74,025
(44,245) $
25,849
2,402
1,142
(14,852) $
5,271
6,772
(5,857)
24
319
158
6,687
1,594
$
$
$
6.25%
4.00%
6.75%
8.50%
4.00%
66
Amounts recognized in the statement of financial position consist of:
(in thousands)
Accrued benefit cost
Intangible assets
Accumulated other comprehensive income, net of tax
Net amount recognized
Pension Benefits
Other Benefits
2003
2002
2003
2002
$
$
14,852
3,974
1,036
19,862
$
$
22,506
2,297
61
24,864
$
$
$
$
In selecting the assumption for expected long−term rate of return on assets, Noble Energy considers the average rate of earnings
expected on the funds to be invested to provide for plan benefits. This includes considering the trusts’ asset allocation, historical
returns on these types of assets, the current economic environment and the expected returns likely to be earned over the life of the
plan. The Company assumes its long−term asset mix will be consistent with its target asset allocation of 70 percent equity and 30
percent fixed income, with a range of plus or minus 10 percent acceptable degree of variation in the plan’s asset allocation. Based on
these factors, the Company expects its pension assets will earn an average of 8.5 percent per annum over the life of the plan. This
basis is consistent with the prior year.
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
Funded status of net periodic benefit obligation
Defined Benefit
Pension Plan
Restoration
Benefit Plan
2003
2002
2003
2002
$
$
$
74,025
80,738
(6,713) $
$
56,660
68,476
(11,816) $
$
13,708
(13,708) $
13,081
(13,081)
Medical trend rates were 10 percent for 2003, grading down to five percent in years 2008 and later. 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
1−Percentage−
Point increase
1−Percentage−
Point decrease
$
$
1,207
10,296
$
$
930
8,166
The following table reflects weighted−average asset allocations by asset category for the Company’s pension benefit plans at
December 31:
Asset category
Equity securities
Fixed income
Other
Total
Target
Allocation
2004
60% − 80%
20% − 40%
0%
0% −
0%
0% −
Plan Assets
2003
2002
70.75%
28.97%
0.28%
100.00%
63.54%
29.57%
6.89%
100.00%
The investment policy for the defined benefit pension plan is determined by the Company’s employee benefits committee (“the
committee”) with input from a third−party investment consultant. Based on a review of historical rates
67
of return achieved by equity and fixed income investments in various combinations over multi−year holding periods and an evaluation
of the probabilities of achieving acceptable real rates of return, the committee has determined the target asset allocation deemed most
appropriate to meet the immediate and future benefit payment requirements for the plan and to provide a diversification strategy which
reduces market and interest rate risk. A one percent decrease in the expected return on plan assets would have resulted in an increase
in benefit expense of $.7 million in 2003.
Noble Energy bases its determination of the asset return component of pension expense on a market−related valuation of assets, which
reduces year−to−year volatility. This market−related valuation recognizes investment gains or losses over a five−year period from the
year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using
the market−related value of assets and the actual return based on the fair value of assets. Since the market−related value of assets
recognizes gains or losses over a five−year period, the future value of assets will be impacted as previously deferred gains or losses
are recorded. As of December 31, 2003, the Company had cumulative asset losses of approximately $7.0 million, which remain to be
recognized in the calculation of the market−related value of assets.
Plan assets include $52.4 million of equity securities and $21.6 million of fixed income securities. The Company contributed cash of
$14.3 million to its pension plans during 2003.
Contributions
The Company expects to make cash contributions of $2.0 million to pension plans during 2004 (unaudited). The decrease in expected
contribution for 2004 is due primarily to the higher actual return on pension plan assets experienced during 2003 and an expectation of
a continued positive return on plan assets during 2004 due to the recovery of market conditions.
Estimated Future Benefit Payments
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
(in thousands)
2004
2005
2006
2007
2008
Years 2009 to 2013
Employee Savings Plan (“ESP”)
Pension
Benefits
Other
Benefits
$
$
$
$
$
$
4,900
5,000
5,200
5,300
5,400
28,600
$
$
$
$
$
$
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
2003
2002
2001
$
2,412
$
2,302
$
2,145
68
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
2003
2002
$
6,255 $
1,510
Other current assets included the following at December 31:
(in thousands)
2003
2002
Deferred tax asset
$
8,144 $
9,584
Other current liabilities included the following at December 31:
(in thousands)
Gas imbalance liabilities
Accrued interest payable
Workers compensation
2003
2002
$
$
$
5,113 $
11,324 $
1,200 $
1,090
11,178
1,200
Crude oil and natural gas operations expense, from continuing operations, included the following for the years ended December 31:
(in thousands)
2003
Lease operating (1)
Production taxes
Workover expense
Total operations expense
2002
Lease operating (1)
Production taxes
Workover expense
Total operations expense
2001
Lease operating (1)
Production taxes
Workover expense
Total operations expense
Consolidated
120,060
$
19,473
6,303
145,836
$
$
$
$
$
82,168
14,315
8,875
105,358
79,733
8,829
15,094
103,656
$
$
$
$
$
$
United
States
75,356
14,601
6,303
96,260
61,217
12,284
8,880
82,381
63,169
8,686
15,094
86,949
$
$
$
$
$
$
North
Sea
10,662
$
Israel(2)
10,662
$
10,817
$
(5)
10,812
$
6,075
$
6,075
$
Equatorial
Guinea
16,319
$
Other
Int’l
17,723
4,872
16,319
$
22,595
9,848
$
286
2,031
9,848
$
2,317
6,775
$
3,714
143
6,775
$
3,857
$
$
$
$
$
$
(1) Lease operating expense includes labor, fuel, repairs, replacements, saltwater disposal, ad valorem taxes and other related lifting
costs.
(2) Production did not begin until 2004.
69
Crude oil and natural gas exploration expense included the following for the years ended December 31:
(in thousands)
2003
Dry hole expense
Unproved lease amortization
Seismic
Staff expense
Other
Total exploration expense
2002
Dry hole expense
Unproved lease amortization
Seismic
Staff expense
Other
Total exploration expense
2001
Dry hole expense
Unproved lease amortization
Seismic
Staff expense
Other
Total exploration expense
Consolidated
63,637
$
33,381
17,674
30,182
3,944
148,818
$
$
$
United
States
North
Sea
32,408
25,296
15,903
17,483
3,601
94,691
$
$
4,023
1,264
1,662
3,105
449
10,503
$
$
Israel
6,711
900
$
214
Equatorial
Guinea
Other
Int’l
$
51
83
20,495
5,921
58
9,297
(106)
35,665
7,825
$
134
$
$
$
81,396
21,254
20,492
24,928
2,631
150,701
$
$
64,449
19,426
14,282
20,081
2,457
120,695
$
$
544
178
827
2,833
828
5,210
$
$
$
$
1,341
900
1,671
54
2,625
$
1,341
$
16,403
750
2,371
1,960
(654)
20,830
$
$
99,684
17,213
15,607
17,148
2,444
152,096
$
$
54,810
15,112
13,328
14,431
2,811
100,492
$
$
28,992
1,725
2,209
1,605
419
34,950
$
$
$
$
375
5
39
380
$
39
$
15,882
1
26
1,112
(786)
16,235
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 Instruments and Hedging Activities
Cash Flow Hedges – The Company, from time to time, uses various derivative instruments in connection with anticipated crude oil
and natural gas sales to minimize the impact of product price fluctuations. Such instruments include fixed price hedges, variable to
fixed price swaps, costless collars and other contractual arrangements. Although these derivative instruments expose the Company to
credit risk, the Company takes reasonable steps to protect itself from nonperformance by its counterparties including periodic
assessment of necessary provisions for bad debt allowance; however, the Company is not able to predict sudden changes in its
counterparties’ creditworthiness. The Company accounts for its derivative instruments under SFAS No. 133, “Accounting for
Derivative Instruments and Hedging Activities,” as amended, and has elected to designate its derivative instruments as cash flow
hedges. Derivative instruments designated as cash flow hedges are reflected at fair value on the Company’s consolidated balance
sheets. Changes in fair value, to the extent the hedge is effective, are reported in AOCI until the forecasted transaction occurs. Gains
and losses from such derivative instruments related to the Company’s crude oil and natural gas production and which qualify for
hedge accounting treatment are recorded in oil and gas sales and royalties on the Company’s consolidated statements of operations
upon sale of the associated products. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair
value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in other income.
70
During 2003, 2002 and 2001, the Company entered into various crude oil and natural gas fixed price swaps, costless collars and
costless collar combinations related to its crude oil and natural gas production. The tables below depict the various transactions.
Natural Gas
Hedge MMBTUpd
Fixed price range
Floor price range
Ceiling price range
Percent of daily production
Crude Oil
Hedge Bpd
Fixed price
Floor price range
Ceiling price range
Percent of daily production
2003
190,038
2002
170,274
$3.25 − $3.80
$4.00 − $5.25
$2.00 − $3.50
$2.45 − $5.10
2001
16,947
$5.23 − $5.41
$3.25 − $5.00
$4.60 − $6.25
56%
50%
5%
2003
15,793
2002
5,247
2001
126
27.81
$
$23.00 − $27.00
$27.20 − $35.05
$23.00 − $24.00
$29.30 − $30.10
44%
18%
.5%
During 2003, 2002 and 2001, the Company included a reduction of $67.5 million and gains of $5.9 million and $5.1 million,
respectively, related to its cash flow hedges in oil and gas sales and royalties. During 2003, 2002 and 2001, no gains or losses were
reclassified into earnings as a result of the discontinuance of hedge accounting treatment. During 2003, the Company recorded $.5
million of ineffectiveness related to its cash flow hedges. No ineffectiveness was recorded for 2002 and 2001.
In 2001, the Company only had financial derivatives in the fourth quarter. Of these fourth quarter derivatives, 25,000 MMBTU of
natural gas per day was terminated early. Amounts in AOCI were reclassified into earnings in the same periods during which the
hedged forecasted transaction affected earnings, resulting in an increase in oil and gas sales and royalties of $6.3 million during the
fourth quarter of 2001. As a result, the Company recognized an additional $.70 per MMBTU on the 25,000 MMBTU of natural gas
per day in 2001.
As of December 31, 2003, 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:
Production
Period
1Q 2004
2Q 2004
3Q 2004
4Q 2004
Natural Gas
Crude Oil
MMBTUpd
120,000
120,000
120,000
120,000
Price
Per MMBTU
Floor − Ceiling
$4.81 − $7.77
$4.06 − $5.95
$4.19 − $5.99
$4.19 − $6.42
Bopd
15,000
15,000
15,000
5,000
Price
Per Bbl
Floor − Ceiling
$25.33 − $31.53
$24.83 − $31.22
$25.00 − $31.13
$24.00 − $30.00
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 ceiling price in respect of each calculation period. The amount payable by the fixed price payor, if
the floating price is below the
71
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.
Accumulated Other Comprehensive Income (Loss) – As of December 31, 2003 and 2002, the balance in AOCI included net deferred
losses of $7.6 million and $14.6 million, respectively, related to the fair value of crude oil and natural gas derivative instruments
accounted for as cash flow hedges. The net deferred losses are net of deferred income tax benefit of $4.1 million and $7.9 million,
respectively.
If commodity prices were to stay the same as they were at December 31, 2003, approximately $11.2 million of crude oil and natural
gas derivative instruments would be recorded in earnings during the next twelve months as the forecasted transactions occur, and
would be recorded as a reduction in oil and gas sales and royalties. Any actual increase or decrease in revenues will depend upon
market conditions over the period during which the forecasted transactions occur. All forecasted transactions currently being hedged
with crude oil and natural gas derivative instruments designated as cash flow hedges are expected to occur by December 2004.
Other Derivative Financial Instruments – In addition to the derivative instruments pertaining to the Company’s production as
described above, NEMI, from time to time, employs various derivative instruments in connection with its purchases and sales of
third−party production to lock in profits or limit exposure to natural 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.
NEMI records gains and losses on derivative instruments using mark−to−market accounting. Under this accounting method, the
changes in the market value of outstanding financial instruments are recognized as gains or losses in the period of change. NEMI
recorded a loss of $.2 million, a gain of $.9 million and a loss of $.5 million in GMP proceeds during 2003, 2002 and 2001,
respectively, related to derivative instruments.
Receivables/Payables Related to Crude Oil and Natural Gas Derivative Financial Instruments – At December 31, 2003, the
Company’s consolidated balance sheet included a receivable of $56.1 million and a payable of $67.6 million related to crude oil and
natural gas derivative financial instruments. At December 31, 2002, the Company’s consolidated balance sheet included a receivable
of $10.3 million and a payable of $32.3 million related to crude oil and natural gas derivative financial instruments.
During 2003, the Company had contracts with Enron North America Corporation (“ENA”) that resulted in gains of $6.9 million (net
of allowance) included in GMP proceeds. In addition, as of December 31, 2003, the Company had NYMEX−related transactions with
ENA totaling 149 contracts with a mark−to−market receivable value of $1.8 million. For additional discussion of ENA matters, see
“Note 10 − Commitments and Contingencies” of this Form 10−K.
Interest Rate Lock – The Company occasionally enters into forward contracts or swap agreements to hedge exposure to interest rate
risk. Changes in fair value of interest rate swaps or interest rate “locks” used as cash flow hedges are reported in AOCI, to the extent
the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense. At
December 31, 2003, the Company’s consolidated balance sheet included a payable of $4.0 million related to an outstanding interest
rate lock. The amount of deferred loss included in AOCI at December 31, 2003 was $2.6 million, net of tax.
Note 9 − Unconsolidated Subsidiaries
Through its ownership in AMCCO, the Company owns a 45 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−2 senior secured notes
due December 15, 2004 to fund construction payments owed in connection with the construction of its methanol plant. The
Company’s investment in the methanol plant is included in investment in unconsolidated subsidiaries. The $125 million Series A−2
notes are in current installments of long−term debt on the Company’s balance sheet.
72
The plant construction started during 1998 and initial production of commercial grade methanol commenced May 2, 2001. 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 of natural gas from the 34 percent−owned Alba field. The methanol plant has a contract
through 2026 to purchase natural gas from the Alba field.
AMCCO, AMPCO, AMPCO Marketing LLC, AMPCO Services LLC and Samedan Methanol are accounted for using the equity
method.
The following are the summarized balance sheets at December 31 and the statements of operations for the years ended December 31
for subsidiaries accounted for using the equity method:
Consolidated Balance Sheets (Unaudited)
Equity Method Subsidiaries
(in thousands)
Assets
Current assets
Non−current assets − net of depreciation
Total Assets
Liabilities, Minority Interest and Members’ Equity
Current liabilities
Members’ equity
Total Liabilities, Minority Interest and Members’ Equity
Consolidated Statements 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)
Loss on early extinguishment of debt (1)
Administrative
Total Expenses
Net Income (Loss)
2003
2002
73,604
397,084
470,688
39,855
430,833
470,688
$
$
$
$
74,832
412,134
486,966
37,419
449,547
486,966
$
$
$
$
2003
2002
2001
$
$
$
$
$
$
171,126
17,232
188,358
76,244
112,114
20,018
5
3,686
23,709
88,405
$
$
$
$
$
$
97,476
18,471
115,947
71,687
44,260
$
$
$
20,763
$
3,076
23,839
20,421
$
$
43,343
5,346
48,689
28,548
20,141
8,427
4,363
7,013
24,776
317
44,896
(24,755)
(1) During 2001, the Company’s partner called its Series A−1 Secured Notes. A prepayment penalty associated with this early
extinguishment was fully allocated to the partner and the Company did not recognize any portion of this loss in its financial
statements.
73
Note 10 − Commitments and Contingencies
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.
On October 15, 2002, Noble Gas Marketing, Inc. and Samedan Oil Corporation, 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 $12 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.
On January 13, 2003, the Noble Defendants filed an answer to ENA’s complaint. On January 29, 2003, the Noble Defendants filed the
Motion of Noble Energy Marketing, Inc., as Successor to Noble Gas Marketing, Inc., and Noble Energy, Inc., as Successor to
Samedan Oil Corporation, to Compel Arbitration. On March 4, 2003, the Court issued its Order Governing Mediation of Trading
Cases and Appointing the Honorable Allan L. Gropper as Mediator (the “Mediation Order”) which, among other things, abated this
case and referred it to mediation along with other pending adversary proceedings in the Enron bankruptcy cases which involve
disputes arising from or in connection with commodity trading contracts. Pursuant to the Mediation Order, the Honorable Allan L.
Gropper (United States Bankruptcy Judge for the Southern District of New York) is acting as mediator for this case and the other
trading cases which have been referred to him. The mediation for this case was held on December 17, 2003 and no resolution was
reached.
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. During 2002, the Company changed the composition of its reportable components due to
changes in the significance of its international business. This was due to the completion of international development projects in
China, Ecuador, Equatorial Guinea and the North Sea. Amounts in the 2001 financial statements were reclassified to conform to the
2002 composition of reportable components.
74
Year Ended December 31, 2003
(Dollars in Thousands)
Consolidated United States
North Sea
Israel
Equatorial
Guinea
Other Int’l,
Corporate &
Marketing
$
364,382 $
474,762
153,891 $
451,476
81,019 $
19,539
$
65,016
3,628
$
68,158
58,022
40,626
5,036
1,010,986
145,836
14,679
148,818
59,114
50,846
309,343
31,937
52,466
9,331
46,977
869,347
919
606,286
1,105
101,663
127
127
96,260
94,691
10,662
9,024
10,503
7,825
134
40,626
109,270
16,319
28,219
254,041
31,937
15,884
40
5
6,115
603
8,449
882
501,262
59,290
7,870
23,171
64,456
119
68,158
58,022
2,885
193,640
22,595
5,655
35,665
59,114
50,846
20,928
35,974
46,977
277,754
141,639
(9,325)
105,024
(9,325)
(8,983)
(8,983)
42,373
(7,743)
86,099
(84,114)
$
123,331 $
86,716 $
42,373 $ (7,743) $
86,099
$
(84,114)
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
Impairment of Operating Assets
SG&A
Accretion of Asset Retirement
Obligation
Interest Expense (net)
Total Costs and Expenses
OPERATING INCOME (LOSS)
FROM CONTINUING
OPERATIONS
DISCONTINUED OPERATIONS
CUMULATIVE EFFECT OF
SFAS 143
INCOME (LOSS) BEFORE
TAXES
LONG−LIVED ASSETS
(PRIMARILY PROPERTY,
PLANT AND EQUIPMENT,
NET)
$ 2,099,741 $
977,583 $
77,293 $253,482
$ 370,430
$
$
420,953
753,584
TOTAL ASSETS
$ 2,842,649 $ 1,037,106 $
163,381 $267,915
$ 620,663
75
Year Ended December 31, 2002
(Dollars in Thousands)
Consolidated
United States
North Sea
Israel
Equatorial
Guinea
Other Int’l,
Corporate &
Marketing
$
257,435
351,591
$
112,010
331,935
$
72,041
19,497
$
$
45,830
3,052
$
64,517
18,257
9,532
1,246
702,578
105,358
16,441
150,701
53,982
15,946
236,881
47,664
47,709
674,682
100
444,045
82,381
120,695
389
91,927
10,812
9,618
5,210
(8)
(8)
2,625
9,532
58,414
9,848
1,341
192,708
27,768
28,279
630
31
10
5,849
2,045
423,552
54,549
2,666
19,083
27,554
(2,893)
64,517
18,257
765
108,200
2,317
6,823
20,830
53,982
15,946
10,014
17,211
47,709
174,832
27,896
14,703
20,493
14,703
37,378
(2,674)
39,331
(66,632)
$
42,599
$
35,196
$
37,378
$ (2,674) $
39,331
$
(66,632)
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
OPERATING INCOME (LOSS)
FROM CONTINUING
OPERATIONS
DISCONTINUED OPERATIONS
INCOME (LOSS) BEFORE
TAXES
LONG−LIVED ASSETS
(PRIMARILY PROPERTY,
PLANT AND EQUIPMENT,
NET)
TOTAL ASSETS
$ 2,730,015
$ 1,337,017
$ 2,139,785
$ 1,225,501
89,316
$180,267
$ 154,231
109,868
$187,429
$ 406,131
$
$
490,470
689,570
$
$
76
Year Ended December 31, 2001
(Dollars in Thousands)
Consolidated
United States
North Sea
Israel
Equatorial
Guinea
Other Int’l,
Corporate &
Marketing
$
214,083
502,856
$
108,464
479,435
$
39,972
22,850
$
$
38,841
2,201
$
64,640
6,981
953
789,513
103,656
16,012
152,096
51,932
233,516
44,164
38,007
639,383
(267)
587,632
86,949
100,492
202,732
26,554
416,727
1,299
64,121
6,075
8,772
34,950
16,537
2,699
69,033
6,981
183
48,206
6,775
39
3,889
917
11,620
380
23
3
406
26,806
(1,630)
64,640
(262)
89,554
3,857
7,240
16,235
51,932
10,335
13,991
38,007
141,597
150,130
74,480
170,905
74,480
(4,912)
(406)
36,586
(52,043)
$
224,610
$
245,385
$
(4,912) $
(406) $
36,586
$
(52,043)
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
OPERATING INCOME (LOSS)
FROM CONTINUING
OPERATIONS
DISCONTINUED OPERATIONS
INCOME (LOSS) BEFORE
TAXES
LONG−LIVED ASSETS
(PRIMARILY PROPERTY,
PLANT AND EQUIPMENT,
NET)
$ 1,953,211
$ 1,308,504
$
$
103,781
$ 101,407
114,563
$ 107,407
$
$
87,461
220,231
$
$
352,058
624,998
TOTAL ASSETS
$ 2,479,848
$ 1,412,649
77
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.
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.
As of June 10, 2003, the Company and the bank amended the agreement to delete the provisions that allowed the Company to net
settle the contract.
The program was scheduled to mature in January 2003 but was extended to January 2004. Under the provisions of the agreement with
the bank, the Company could choose to purchase the shares from the bank, issue additional shares to the bank to the extent that the
share price had decreased, pay the bank a net amount of cash to the extent that the share price had decreased, or receive from the bank
a net amount of cash to the extent that the share price had increased. The bank had the right to terminate the agreement prior to the
maturity date if the Company’s share price decreased by 50 percent (to $16.77 per share) or if the Company’s credit rating was
downgraded below BBB− (S&P) or Baa3 (Moody’s). If either event occurred and the bank exercised its right to terminate, the
Company still retained the right to settle in cash or additional shares. The agreement limited 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 would be an addition or
reduction to the Company’s capital in excess of par value. As of December 31, 2002, the fair value of the Company’s obligation under
the contract was 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.
During the second quarter of 2003, the Company adopted SFAS No. 150, “Accounting for Certain Financial Instruments with
Characteristics of Both Liabilities and Equity.” As a result, the Company recorded an additional 1,044,454 shares of treasury stock at a
cost of $36.6 million and an obligation of $36.6 million. In December 2003, the Company paid the obligation in full.
Note 13 − Discontinued Operations
Pursuant to SFAS No. 144, “Accounting for the Impairment or Disposal of Long−Lived Assets,” which replaced APB Opinion No. 30
for the disposal of segments of a business, the Company’s consolidated financial statements have been reclassified for all periods
presented to reflect the operations and assets of the properties being sold as discontinued operations. The net income from
discontinued operations was classified on the consolidated statements of operations as “Discontinued Operations, Net of Tax.”
During 2003, the Company identified five domestic property packages for disposition. Bids have now been received on all five
packages. During 2003, property sales closed on four of the five packages, with the remaining property package expected to close
during the first half of 2004. Total pretax proceeds on all five packages, before closing adjustments, are expected to be in excess of
$110.0 million.
The Company recorded a loss, net of tax, related to discontinued operations of $6.1 million in 2003. Included in the discontinued
operations loss was a $59.2 million ($38.5 million, net of tax) non−cash write down to market value for certain of the five property
packages. The Company has reclassified the results of operations associated with the five property packages for 2001 and 2002 to
discontinued operations. This reclassification did not have an effect on net income as previously reported for 2001 and 2002. As a
result of the reclassification, oil and gas sales and royalties are lower, as well as the associated oil and gas operations and DD&A
expense.
78
Summarized results of discontinued operations are as follows:
(dollars in thousands)
Revenues:
Oil and gas sales and royalties
Costs and Expenses:
Write down to market value and realized loss
Oil and gas operations
Depreciation, depletion and amortization
Income (Loss) Before Income Taxes
Income Tax Provision (Benefit)
Income (Loss) From Discontinued Operations
2003
Year ended December 31,
2002
2001
$
106,339
$
91,576
$
154,873
59,171
27,731
28,762
115,664
(9,325)
(3,264)
(6,061) $
$
28,468
48,405
76,873
14,703
5,146
9,557
$
29,893
50,500
80,393
74,480
26,068
48,412
The long−term debt of the Company is recorded at the consolidated level and is not reflected by each component. Thus, the Company
has not allocated interest expense to the discontinued operations.
79
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. Noble Energy has engaged independent third−party reserve engineers to perform an audit of the Company’s procedures and
methods used to estimate proved reserves for each of the three years 2001 − 2003. The audit for 2003 included a review of the areas
representing 80 percent of the Company’s reserves. In addition, Noble Energy has obtained independent third−party estimates for
several major international properties including those in Ecuador, Equatorial Guinea and Israel. 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.
The SEC requested clarification, which the Company provided, as to the Company’s Israel and Equatorial Guinea gas reserves
recorded in excess of existing contract amounts. SEC guidelines do not limit reserve bookings only to contracted volumes if it can be
demonstrated that there is reasonable certainty that a market exists, which the Company believes exists in both of these situations. The
Israel gas contract is for a period of 11 years. The Israel gas market, as estimated by the Israeli Ministry of National Infrastructure,
from 2005 to 2020, is twenty times greater than Noble Energy’s uncontracted net estimated proved reserves. In Equatorial Guinea, the
gas contract, which runs through 2026, is between the field owners and the methanol plant owners. Noble Energy, through its
subsidiaries, holds a working interest in the field as well as an interest in the methanol plant. The Company has recorded reserves
through the end of the concession’s term in 2040. Noble Energy has obtained independent third−party engineer reserve estimates for
both of these projects.
The following definitions apply to the Company’s categories of proved reserves:
Proved Reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which
geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under
existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
Proved Developed Reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods.
Proved Undeveloped Reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells
on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
For complete definitions of proved natural gas, natural gas liquids and crude oil reserves, refer to the SEC Regulation S−X,
Rule 4−10(a)(2), (3) and (4).
80
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.
Proved reserves as of:
January 1, 2003
Revisions of previous
estimates
Extensions, discoveries and
other additions
Production
Sale of minerals in place
Purchase of minerals in place
December 31, 2003
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 developed gas
reserves as of:
January 1, 2004
January 1, 2003
January 1, 2002
January 1, 2001
Natural Gas and Casinghead Gas (MMcf)(1)
United
States
621,716
Argentina
Ecuador
Equatorial
Guinea (2)
3,887
84,993
425,420
Israel (2)
450,307
North
Sea
14,478
Total
1,600,801
3,070
(1,147)
2,147
182
4,392
8,644
44,463
(106,609)
(10,406)
5,824
558,058
(292)
(7,842)
126,962
(14,566)
(5,059)
2,448
79,298
537,998
450,307
13,811
171,425
(134,368)
(10,406)
5,824
1,641,920
751,283
4,348
87,500
438,214
378,001
20,661
1,680,007
(37,566)
(37)
281
(245)
18
(37,549)
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
115,112
(141,626)
(20,290)
5,147
1,600,801
752,387
4,544
87,500
383,292
218,154
28,752
1,474,629
36
371
(603)
(46,886)
129,172
(134,507)
(246)
51,363
751,283
(2,550)
159,847
(1,583)
108,864
66,410
(8,938)
(6,508)
195,953
(150,556)
(246)
51,363
1,680,007
4,348
87,500
438,214
378,001
20,661
506,457
576,378
721,926
690,301
2,197
3,664
3,996
4,544
25,130
34,436
462,474
425,420
438,214
383,292
378,001
13,811
14,478
20,661
25,652
1,388,070
1,054,376
1,184,797
1,103,789
(1) The Company’s international proved reserves do not differ materially from the volumes that would be calculated under the
economic interest method.
(2) Includes reserves in excess of volumes under gas sales contracts.
81
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, 2003
Revisions of previous estimates
Extensions, discoveries and other
additions
Production
Sale of minerals in place
Purchase of minerals in place
December 31, 2003
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 developed oil reserves as
of:
January 1, 2004
January 1, 2003
January 1, 2002
January 1, 2001
Crude Oil and Condensate (Bbls in thousands)(1)
United
States
62,023
1,216
1,949
(7,402)
(15,482)
Argentina
China
9,283
(91)
768
(1,039)
10,930
609
(1,203)
Equatorial
Guinea
111,019
(333)
4,840
(2,328)
North
Sea
8,223
3,654
(2,705)
(712)
Total
201,478
5,055
7,557
(14,677)
(16,194)
42,304
8,921
10,336
113,198
8,460
183,219
71,672
(5,331)
2,929
(6,652)
(732)
137
62,023
69,700
324
7,453
(7,363)
(37)
1,595
71,672
34,246
52,847
64,534
58,903
10,277
36
(1,030)
9,768
1,162
79,790
(34)
33,182
(1,919)
11,114
(27)
(2,864)
9,283
10,930
111,019
8,223
9,437
(6)
1,846
(1,000)
9,768
47,446
(272)
34,303
(1,687)
12,418
407
(1,711)
10,277
9,768
79,790
11,114
8,004
8,331
8,866
9,437
10,336
10,930
113,198
78,746
61,897
47,446
8,460
8,223
11,114
5,728
182,621
(5,356)
37,273
(12,465)
(732)
137
201,478
148,769
453
43,602
(11,761)
(37)
1,595
182,621
174,244
159,077
146,411
121,514
(1) The Company’s international proved reserves do not differ materially from the volumes that would be calculated under the
economic interest method.
82
Oil and Gas Operations (Unaudited)
Aggregate results of continuing operations for each period ended December 31, in connection with the Company’s crude oil and
natural gas producing activities, are shown below.
(in thousands)
December 31, 2003
Revenues
Production costs
Transportation
E&P corporate
Exploration expenses
DD&A and valuation provision
Impairment of operating assets
Accretion expense
Income (loss)
Income tax expense (benefit)
Result of continuing operations
from producing activities
(excluding corporate overhead and
interest costs)
December 31, 2002
Revenues
Production costs
Transportation
E&P corporate
Exploration expenses
DD&A and valuation provision
Income (loss)
Income tax expense
Result of continuing operations
from producing activities
(excluding corporate overhead and
interest costs)
December 31, 2001
Revenues
Production costs
Transportation
E&P corporate
Exploration expenses
DD&A and valuation provision
Income (loss)
Income tax expense (benefit)
Result of continuing operations
from producing activities
(excluding corporate overhead and
interest costs)
United
States
605,367
112,725
$
Equatorial
Guinea
$
68,644
16,319
$
Israel
$
North
Sea
100,558
10,662
9,024
$
15,884
71,802
278,426
31,937
8,449
86,144
17,795
603
134
6,101
45,487
21,770
5
6,925
910
(7,840)
(4,121)
9,239
29,405
882
41,346
19,586
$
Other
Int’l
64,575
18,538
5,655
1,866
28,011
23,795
(13,290)
9,479
Total
839,144
158,244
14,679
18,358
116,111
338,637
31,937
9,331
151,847
64,509
$
$
$
$
68,349
$
23,717
$
(3,719) $
21,760
$
(22,769) $
87,338
444,121
86,342
$
45,830
6,795
$
$
27,768
102,323
209,905
17,783
6,559
2,045
1,341
5,835
29,814
13,825
10
1,725
909
(2,644)
$
91,538
10,813
9,618
630
5,032
28,350
37,095
16,360
$
27,537
5,180
6,823
1,090
20,733
9,606
(15,895)
666
609,026
109,130
16,441
31,543
131,154
254,605
66,153
37,410
11,224
$
15,989
$
(2,644) $
20,735
$
(16,561) $
28,743
588,036
90,943
$
38,841
4,464
$
$
25,418
86,619
216,305
168,751
59,232
917
39
3,830
29,591
14,429
3
5
382
(390)
$
62,823
6,075
8,772
2,699
33,224
18,171
(6,118)
(2,721)
$
27,239
5,746
7,240
1,929
17,021
8,679
(13,376)
(700)
716,939
107,228
16,012
30,966
136,908
247,367
178,458
70,240
$
109,519
$
15,162
$
(390) $
(3,397) $
(12,676) $
108,218
83
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.
(in thousands)
December 31, 2003
Property acquisition costs
Proved
Unproved
Total
Exploration costs
Development costs
Asset retirement obligation
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
United
States
Equatorial
Guinea
Israel
North
Sea
Other
Int’l
Total
$
$
$
$
$
$
$
$
$
$
$
$
$
1,419
10,184
11,603
127,450
98,717
12,566
7,873
28,023
35,896
153,437
131,244
91,251
76,808
168,059
134,247
279,297
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
134
222,315
1,351
51,839
4,003
10,364
$
$
$
$
$
$
$
$
$
$
$
$
$
6,925
66,751
1,725
14,767
131
11,163
(125) $
(125) $
$
$
10,086
6,747
6,114
$
115
(238)
(123) $
$
5,062
$
9,892
6,318
2,167
8,485
34,766
17,338
$
$
$
$
50
50
8,828
7,249
2,730
2,730
20,935
60,934
2,310
2,310
19,233
75,910
$
$
$
$
$
$
$
$
$
$
$
$
$
1,294
10,234
11,528
153,423
401,779
18,680
7,988
30,515
38,503
182,510
268,676
97,569
81,285
178,854
192,380
394,072
Development costs include $274.6 million, $245.6 million and $191.1 million spent to develop proved undeveloped reserves in 2003,
2002 and 2001, respectively.
Aggregate Capitalized Costs (Unaudited)
Aggregate capitalized costs relating to the Company’s crude oil and natural gas producing activities, including asset retirement costs
and related accumulated DD&A, as of December 31 are shown below:
(in thousands)
Unproved oil and gas properties
Proved oil and gas properties
Accumulated DD&A
Net capitalized costs
U. S.
155,426
2,302,002
2,457,428
(1,508,381)
949,047
$
$
$
$
2003
Int’l
10,519
818,102
828,621
(252,650)
575,971
$
Total
165,945
3,120,104
3,286,049
(1,761,031)
$ 1,525,018
$
U. S.
138,319
3,053,256
3,191,575
(1,972,282)
$ 1,219,293
2002
Int’l
$
$
16,532
1,069,914
1,086,446
(189,540)
896,906
$
Total
154,851
4,123,170
4,278,021
(2,161,822)
$ 2,116,199
Amounts at December 31, 2003 include an asset retirement cost of $82.2 million for the U.S. and $14.3 million for International.
84
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, 2003, 2002 and 2001 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, 2003
(in millions of dollars)
Future cash inflows
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
10% annual discount for estimated
timing of cash flows
Standardized measure of discounted
future net cash flows
December 31, 2002
(in millions of dollars)
Future cash inflows
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
10% annual discount for estimated
timing of cash flows
Standardized measure of discounted
future net cash flows
December 31, 2001
(in millions of dollars)
Future cash inflows
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
10% annual discount for estimated
timing of cash flows
Standardized measure of discounted
future net cash flows
United
States
Ecuador
Equatorial
Guinea
Israel
North
Sea
Other
Int’l
Total
$
4,425 $
986
339
1,033
2,067
317 $
46
49
86
136
$
3,391 $ 1,177
139
84
311
643
635
199
1,224
1,333
833
50
760
292
$
316
113
25
78
100
11
$
582
248
19
94
221
76
10,208
2,167
715
2,826
4,500
2,022
$
1,234 $
86 $
573 $
351
$
89
$
145
$
2,478
$
4,743 $
1,119
387
985
2,252
268 $
42
31
33
162
$
3,111 $ 1,181
201
100
263
617
445
216
860
1,590
877
59
953
301
$
294
98
12
68
116
21
$
648
216
22
111
299
93
10,245
2,121
768
2,320
5,036
2,304
$
1,375 $
103 $
637 $
316
$
95
$
206
$
2,732
$
3,399 $
1,239
379
437
1,344
264 $
46
57
26
135
1,576 $
267
114
598
597
562
56
406
$
900
47
103
193
557
364
$
281
68
16
49
148
25
$
317
124
44
24
125
65
6,737
1,791
713
1,327
2,906
1,478
$
782 $
79 $
191 $
193
$
123
$
60
$
1,428
The future net cash inflows for 2003, 2002 and 2001 do not include cash flows relating to the Company’s anticipated future methanol
or power sales.
85
Future cash inflows are computed by applying year−end prices, adjusted for location and quality differentials on a
property−by−property basis, to year−end quantities of proved reserves, except in those instances where fixed and determinable price
changes are provided by contractual arrangements at year−end. The discounted future cash flow estimates do not include the effects of
the Company’s derivative financial instruments. See the following table for average prices per region:
December 31, 2003
Average oil price per Bbl
Average gas price per Mcf
December 31, 2002
Average oil price per Bbl
Average gas price per Mcf
December 31, 2001
Average oil price per Bbl
Average gas price per Mcf
United
States
Ecuador
Equatorial
Guinea
Israel
North
Sea
Other
Int’l
Total
$
$
$
$
$
$
30.16
5.64
29.19
4.72
16.43
2.96
$
$
$
$
$
$
$
$
$
$
$
$
4.00
3.15
3.02
28.76
.25
27.10
.24
18.38
.25
$
$
$
$
$
$
$
$
$
$
$
$
2.61
2.62
2.38
30.64
4.15
28.88
3.89
19.24
3.27
$
$
$
$
$
$
30.16
.38
32.00
.30
15.58
.97
$
$
$
$
$
$
29.32
2.95
28.31
2.84
17.35
2.12
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
$96.8 million or $52.7 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 development costs include $51.9
million, $62.2 million and $31.5 million that the Company expects to spend in 2004, 2005 and 2006, respectively, to develop proved
undeveloped reserves.
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, 2003, the Company estimated natural gas imbalance receivables of $22.2 million and estimated natural gas
imbalance liabilities of $17.0 million; at year−end 2002, $20.1 million in receivables and $15.4 million in liabilities; and at year−end
2001, $20.9 million in receivables and $15.5 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, 2003, 2002 and 2001.
86
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
$
2003
2002
2001
$
2,732
247
115
(148)
(115)
(312)
405
(793)
243
(250)
354
$
1,428
486
(158)
(243)
(13)
1,636
208
(553)
254
(667)
354
4,074
448
114
(128)
108
(3,376)
564
(713)
220
908
(791)
$
2,478
$
2,732
$
1,428
87
Supplemental quarterly financial information for the years ended December 31, 2003 and 2002 is as follows:
Supplemental Quarterly Financial Information
(Unaudited)
(in thousands except per share amounts)
2003
Revenues
Income (loss) from continuing operations before taxes
Income (loss) from continuing operations
Cumulative effect of change in accounting principle, net
of tax
Discontinued operations, net of tax
Net income (loss)
Basic earnings (loss) per share:
Income from continuing operations
Cumulative effect of change in accounting principle, net
of tax
Discontinued operations, net of tax
Net income (loss)
Diluted earnings (loss) per share:
Income from continuing operations
Cumulative effect of change in accounting principle, net
of tax
Discontinued operations, net of tax
Net income (loss)
2002
Revenues
Income (loss) from continuing operations before taxes
Income (loss) from continuing operations
Discontinued operations, net of tax
Net income (loss)
Basic earnings (loss) per share:
Income (loss) from continuing operations
Discontinued operations, net of tax
Net income (loss)
Diluted earnings (loss) per share:
Income (loss) from continuing operations
Discontinued operations, net of tax
Net income (loss)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Mar. 31,
June 30,
Sept. 30,
Dec. 31,
Quarter Ended
266,723
58,236
32,712
$
$
$
(5,839) $
$
7,984
$
34,857
247,167
39,630
25,809
3,260
29,069
0.57
$
(0.10) $
$
0.14
$
0.61
0.56
$
(0.10) $
$
0.14
$
0.60
0.45
0.06
0.51
0.45
0.06
0.51
143,843
$
(18,136) $
(13,174) $
(1,924) $
(15,098) $
167,160
22,874
13,179
3,940
17,119
(0.23) $
(0.03) $
(0.26) $
(0.23) $
(0.03) $
(0.26) $
0.23
0.07
0.30
0.23
0.07
0.30
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
244,344
48,239
31,567
3,549
35,116
0.56
0.06
0.62
0.55
0.07
0.62
$
$
$
$
$
$
$
$
$
$
$
$
$
$
252,752
(4,466)
(196)
(20,854)
(21,050)
0.00
(0.37)
(0.37)
0.00
(0.37)
(0.37)
180,381
$
(7,518) $
(4,171) $
2,981
$
(1,190) $
211,194
30,676
12,261
4,560
16,821
(0.07) $
0.05
$
(0.02) $
(0.07) $
0.05
$
(0.02) $
0.21
0.08
0.29
0.21
0.08
0.29
The first quarter of 2003 includes a loss from cumulative effect of change in accounting principle, net of tax of $5.8 million ($.10 per
share) due to the adoption of SFAS No. 143. The fourth quarter of 2003 includes impairment of operating assets of $31.9 million
($20.7 million, net of tax). Amounts for 2002 have been reclassified to reflect the adoption of EITF 02−03, “Recognition and
Reporting of Gains and Losses on Energy Trading Contracts,” as of
88
January 1, 2003. The adoption of EITF 02−03 resulted in a decrease in revenues and a decrease in operating expenses of $649.6
million for the year ended December 31, 2002. The adoption of EITF 02−03 had no effect on operating income or cash flow. In
addition, amounts for 2002 have been reclassified to reflect the reporting of discontinued operations.
89
To the Shareholders and Board of Directors of Noble Energy, Inc.:
Independent Auditors’ Report on
Consolidated Financial Statement Schedule
Under date of February 26, 2004, we reported on the consolidated balance sheets of Noble Energy, Inc. as of December 31, 2003 and
2002, and the related consolidated statements of operations, shareholders’ equity and other comprehensive income, and cash flows for
each of the years in the three−year period ended December 31, 2003. In connection with our audits of the aforementioned consolidated
financial statements, we also audited the related consolidated financial statement schedule. The consolidated financial statement
schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial
statement schedule based on our audits.
In our opinion, the consolidated financial statement schedule, when considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
Houston, Texas
February 26, 2004
KPMG LLP
90
NOBLE ENERGY, INC.
VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2003, 2002 and 2001
(in thousands)
Schedule II
Description
2003
Allowance for doubtful accounts (1)
Deferred tax asset valuation allowance (2)
$
2002
Allowance for doubtful accounts
Deferred tax asset valuation allowance
2001
Allowance for doubtful accounts
Deferred tax asset valuation allowance
Balance at
Beginning
of Period
Additions
Charged to
Costs and
Expenses
Charged to
Other
Accounts
Deductions
Balance at
End of
Period
1,510
21,148
638
17,115
645
$
4,745
$
$
$
6,629
6,255
14,519
872
4,033
17,115
1,510
21,148
638
17,115
7
The increase in the allowance for doubtful accounts is related to financial derivative contracts with one of the Company’s
(1)
counterparties.
The decrease in the valuation allowance associated with foreign loss carryforwards was due to the elimination of the
(2)
carryforward and offsetting valuation allowance associated with Vietnam, the elimination of the valuation allowance associated with
Israel and the partial elimination of the valuation allowance associated with China.
91
Atlantic Methanol Production Company, LLC
Financial Statements
For the Years Ended December 31, 2003, 2002 and 2001
92
The Members
Atlantic Methanol Production Company, LLC
Report of Independent Auditors
We have audited the accompanying balance sheet of Atlantic Methanol Production Company, LLC as of December 31, 2003 and
2002, and the related statements of operations, members’ equity and cash flows for the years then ended. 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 Atlantic
Methanol Production Company, LLC as of December 31, 2003 and 2002, and the results of its operations and its cash flows for the
years then ended in conformity with accounting principles generally accepted in the United States.
The accompanying financial statements for 2001 were not audited by us and, accordingly, we do not express an opinion on them.
Ernst & Young LLP
January 28, 2004
Fort Worth, Texas
93
Atlantic Methanol Production Company, LLC
Balance Sheet
(dollars in thousands)
ASSETS
Current Assets:
Cash and cash equivalents
Receivables − affiliates
Accounts receivable − trade
Other receivables
Inventories
Deferred methanol cost (Note 2)
Deferred expenses (Note 2)
Prepaid expenses and deposits
Total current assets
Property, Plant and Equipment:
Plant, net of accumulated depreciation ($47,328 at December 31, 2003 and $29,299 at
December 31, 2002)
Total Assets
LIABILITIES AND MEMBERS’ EQUITY
Current Liabilities:
Accounts payable
Accounts payable − affiliates
Accrued liabilities
Income and other taxes payable
Deferred revenue (Note 2)
Distributions payable
Total current liabilities
Commitments and Contingencies (Notes 3, 5 and 6)
Members’ Equity
Total Liabilities and Members’ Equity
See accompanying notes.
94
December 31,
2003
2002
$
$
$
10,970
10,029
6,177
228
12,054
3,296
1,574
5,025
49,353
373,564
422,917
527
231
11,419
633
15,346
28,156
12,091
7,460
13,552
11,057
5,560
2,876
52,596
388,003
440,599
4,945
444
4,290
16,095
2,530
28,304
394,761
422,917
$
412,295
440,599
$
$
$
$
Atlantic Methanol Production Company, LLC
Statement of Operations
(dollars in thousands)
Revenue:
Methanol sales
Shipping revenue (Note 9)
Sales of purchased third−party methanol (Note 7)
Other
Total Revenue
Costs and Expenses:
Cost of methanol
Shipping
Marketing
Cost of third−party purchased methanol sold (Note 7)
Net bridge cost recovery loss (Note 7)
Depreciation
General and administrative expense
Net profit interest (Note 8)
Ship charter expense (Note 9)
Total Costs and Expenses
$
$
2003
December 31,
2002
2001
(Unaudited)
$
$
171,127
2,306
341
11,829
185,603
27,550
19,011
5,189
428
318
19,197
22,664
5,201
1,079
100,637
$
$
97,476
1,954
11,384
1,800
112,614
21,824
17,709
2,833
15,312
2,134
18,791
15,675
48,159
4,263
1,842
594
54,858
8,790
15,304
1,102
2,526
8,427
9,364
6,524
94,278
52,037
Net Income
$
84,966
$
18,336
$
2,821
See accompanying notes.
95
Atlantic Methanol Production Company, LLC
Statement of Members’ Equity
(dollars in thousands)
Members’ equity, beginning of year:
Contributions
Net income
Distributions declared to members
Members’ equity, end of year
See accompanying notes.
2003
December 31,
2002
2001
(Unaudited)
$
$
412,295
$
84,966
(102,500)
394,761
$
413,919
15,340
18,336
(35,300)
412,295
$
$
365,558
46,540
2,821
(1,000)
413,919
96
Atlantic Methanol Production Company, LLC
Statement of Cash Flows
(dollars in thousands)
Cash Flows from Operating Activities
Net income
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation
(Increase) decrease in receivables − affiliates
(Increase) decrease in receivables − trade
Increase in receivables − others
Increase in prepaid expenses and deposits
(Increase) decrease inventories
(Increase) decrease in deferred methanol cost
Increase in deferred expenses
Increase (decrease) in accounts payable
Increase (decrease) in accounts payable − affiliates
Increase (decrease) in accrued liabilities
Increase (decrease) in deferred revenue
Net cash provided by operating activities
Cash Flows from Investing Activities
Capital expenditures
Cash Flows from Financing Activities
Capital contributions
Distribution of dividends to members
Net cash used in financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents, beginning of year
Cash and cash equivalents, end of year
See accompanying notes.
97
2003
December 31,
2002
2001
(Unaudited)
$
84,966
$
18,336
$
2,821
19,197
(2,569)
7,374
(228)
(2,148)
(996)
2,263
(1,574)
(3,786)
(214)
7,131
(749)
108,667
$
18,791
(3,189)
(11,837)
(197)
7,760
(5,560)
3,078
(3,434)
(3,047)
16,095
36,796
$
9,364
2,244
(1,715)
(2,679)
(18,817)
1,704
3,878
7,337
4,137
(4,758) $
(13,318) $
(46,130)
(105,030)
(105,030) $
(1,121)
12,091
10,970
$
15,340
(33,770)
(18,430) $
5,048
7,043
12,091
$
46,540
46,540
4,547
2,496
7,043
$
$
$
$
Notes to Financial Statements
December 31, 2003
1. Formation and Nature of Business
Atlantic Methanol Production Company, LLC (the Company) was formed to construct, operate and own a methanol production
facility (the Plant) and related facilities on Bioko Island, Equatorial Guinea. The Company is 90% owned by Atlantic Methanol
Associates, LLC (AMA) and 10% owned by Guinea Equatorial Oil and Gas Marketing Ltd. (GEOGM). AMA is owned 50% by
Marathon E.G. Methanol Limited, which is ultimately a wholly owned subsidiary of Marathon Oil Corporation (Marathon) and 50%
owned by Samedan Methanol, which is an indirect subsidiary of Noble Energy, Inc. (Noble).
Production of methanol began in May 2001. The Plant utilizes natural gas supplied by the nearby Alba Field under a 25−year
fixed−price contract of $0.25 per MMBtu. Subsidiaries of Marathon and Noble own 63.3% and 33.7%, respectively, of the Alba Field.
Prior to January 3, 2002 subsidiaries of CMS Energy Corporation (CMS) owned a portion of the Company, the Alba field, AMPCO
Marketing LLC (Note 3), and AMPCO Services LLC (Note 3) now controlled by Marathon and its subsidiaries. The assets of the
Company are recorded at historical cost.
2. Summary of Significant Accounting Policies
Cash and Cash Equivalents
The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash
equivalents.
Inventories
Inventories consist of methanol held in tanks and spare parts for the Plant and are stated at the lower of cost or market, with cost being
determined by the weighted average cost method.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Depreciation is provided on a straight−line basis over the assets estimated useful
lives, and in the case of the Plant, over a 25−year life.
The Company reviews the carrying value of property, plant and equipment for impairment whenever events and circumstances
indicate that the carrying value of an asset may not be recoverable from the estimated future cash flows expected to result from its use
and eventual disposition. In cases where undiscounted expected future cash flows are less than the carrying value, a write−down is
recognized equal to an amount by which the carrying value exceeds the estimated future discounted cash flows. No impairments were
recorded in 2003.
98
Deferred Revenue and Deferred Methanol Cost
Under the Company’s sales agreements with Solvadis Chemag (MG) (Note 6) and AMPCO Marketing, LLC (Marketing) (Note 3)
(collectively the Marketers), risk of physical loss to the methanol transfers when it is loaded on a tanker and leaves port in Equatorial
Guinea. At this point, the Marketers are invoiced a provisional amount for the methanol and are required to pay 30 days subsequent to
arrival of the methanol in the U.S. or Europe. Since final pricing is not known until the Marketers’ resell the product under their
third−party contracts, revenue and the related cost of methanol is deferred until the Marketers resell the methanol to third parties. At
December 31, 2003, there were approximately 49,967 and 30,905 metric tons of methanol held by Marketing and MG, respectively,
that had not been sold to third parties. Revenue from provisional billings of approximately $15.4 million associated with these
volumes is reflected as deferred revenue on the accompanying balance sheet. Cost of methanol related to these volumes of
approximately $3.3 million is reflected as deferred methanol cost on the accompanying balance sheet.
Deferred Expenses
Deferred expenses are shipping costs that have been incurred but are associated with methanol that is included in deferred revenue.
These costs are expensed as the associated methanol in deferred revenue is sold.
Foreign Currency Translation
The U.S. dollar is considered the functional currency of the Company. Transactions that are completed in a foreign currency are
translated into U.S. dollars and recorded in the financial statements. Some costs and revenues are invoiced in Euros, British Pound
Sterling and the Communaute Financiere Africaine Franc (XAF). These costs and revenues are translated to US dollars on a monthly
basis based upon the exchange rate on the last day of the current month.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires
management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent
assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Income Taxes
Deferred income taxes are provided to reflect the future tax consequences of differences between the tax bases of assets and liabilities
and their reported amounts in the financial statements. Deferred income tax assets and liabilities are computed using the currently
enacted tax laws and rates that apply to the periods in which they are expected to affect taxable income.
A valuation allowance is established when it is more likely than not that some portion or all of the deferred tax assets will not be
realized.
Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, and accounts payable. The
carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable are representative of their respective fair
values due to the short−term maturity of these instruments.
99
3. Related Parties
AMPCO Services LLC (Services)
Marathon and Noble, through their respective subsidiaries, formed Services to provide technical and consulting services to their
jointly owned methanol production and marketing companies related to the transportation, storage, marketing, sale and delivery of
methanol. Services bills the Company the cost, plus a 7% mark−up, of fixed asset purchases and expenses incurred on behalf of the
Company, excluding depreciation. Services is equally owned by Noble and Marathon through their various subsidiaries.
At December 31, 2003, the Company had approximately $0.2 million in payables for consulting services received during 2003 by
Services on behalf of the Company, which is included as accounts payable — affiliates on the accompanying balance sheet. During
the year the Company incurred costs of approximately $2.6 million from Services. Such amounts are included in cost of methanol on
the accompanying Statement of Operations.
AMPCO Marketing LLC (Marketing)
Effective January 1, 2001, the Company entered into an agreement to sell to Marketing 300,000 to 600,000 metric tons of methanol on
an annual basis through 2005. The price received under the agreement is based on the price that Marketing is able to resell the
methanol to third parties, less commissions, transportation and storage costs. In turn, Marketing has entered into annual contracts with
third parties to sell methanol on a monthly basis. Pricing under these contracts is generally based on an index price less certain
discounts for volume purchases. Marketing is equally owned by Noble and Marathon through their respective subsidiaries.
Marathon and Noble
Marathon and Noble, through their respective subsidiaries provide the Company with gas for use in the Plant from the nearby Alba
Field. The gas is priced at $0.25 per MMBtu. The Alba Field is owned 63.3% and 33.7% by subsidiaries of Marathon and Noble,
respectively (see Note 5).
4. Income Taxes
Under the Manufacturing and Marketing Agreement (MMA) entered into with the Republic of Equatorial Guinea, the Company is
exempted from Republic corporate income taxes for three years after commercial operations begin. The three−year income tax holiday
excludes the year of first commercial operation. Therefore, the Company will be liable for income taxes beginning in 2005. During the
income tax holiday the Company is recording depreciation for book purposes but is not required to take any reductions to the related
assets carrying value for tax purposes. Accordingly, the Company is creating a deferred tax asset equal to the amount of depreciation
taken for book purposes multiplied by the statutory tax rate of 25%. As of December 31, 2003 this represents an asset of
approximately $11,832,000. The Company has recognized a valuation allowance equal to the deferred tax asset due to the uncertainty
of the timing of future earnings.
100
5. Commitments And Contingencies
Pursuant to the Company’s Limited Liability Company Agreement, no member or manager shall be liable for the debts, obligations, or
liabilities of the Company, including under a judgment, decree or order of a court, except as may be provided in a separate, written
agreement executed by such member or manager wherein they expressly agree to assume such obligations. The Company will
continue to exist in perpetuity absent unanimous approval of the Members.
Litigation
The Company is involved in disputes arising in the ordinary course of business. Management does not believe the outcome of any
such disputes will have a material adverse effect on the Company’s financial position or results of operations.
Gas Purchase Commitment
The Company has a take−or−pay commitment contract to purchase annual quantities of natural gas for use by the Plant. The term of
the contract is 25 years from first supply (May 2, 2001) and can be extended based on agreement of the parties. The minimum annual
contract quantity of gas that must be purchased is 28,000,000 MMBtu on a gross heating value basis from the Alba Field (see Note 1).
The gas is priced at $0.25 per MMBtu. The Alba Field is owned 63.3% and 33.7% by subsidiaries of Marathon and Noble,
respectively. The minimum commitment under this contract is as follows:
2004
2005
2006
2007
2008
2009 and thereafter
Sales Commitments
$
7,000,000
7,000,000
7,000,000
7,000,000
7,000,000
121,333,000
$ 156,333,000
In addition to the sales contract between the Company and Marketing disclosed in Note 3, the Company also entered into contracts
with MG and British Petroleum Oil International (BP), unrelated third parties, to sell 300,000 and 80,000 metric tons, respectively, of
methanol on an annual basis through 2005. The price received under the MG agreement is based on the price MG resells the methanol
to third parties, less commissions, transportation and storage costs. In turn, MG has entered into annual contracts with third parties to
sell methanol on a monthly basis. Pricing under MG’s contracts with third parties are based upon annual contract discounts as applied
to the quarterly European contract price. Several customers’ contracts also include a spot component based upon the spot price at the
time of purchase. In the case of BP, which internally consumes the methanol acquired, the price is based upon the European index
with the spot price impacting the final price. In 2003, the BP contract contains a price cap of EURO 180 per ton of methanol sold.
101
Concentrations of Risk
The Company sells all of its production under agreements with Marketing, MG and BP, as previously disclosed, who in turn resell the
methanol to numerous third parties. In addition, the Company’s ability to produce methanol is dependant upon the natural gas
feedstock received from the Alba Field as disclosed in Note 5.
6. Leases
The Company has leased office space from the Republic for use in training local employees for work at the Plant. The lease requires
semi−annual payments of $120,000 and expires in August 2007.
The Company entered into operating lease agreements on March 23, 1999 for two oil/methanol tankers (vessels) to transport methanol
produced by the Plant to the markets serviced by MG, BP and Marketing. Each vessel has a capacity of approximately 42,000 metric
tons of methanol. The vessel lease agreements are for a period of 15 years and can be extended for an additional five−year period at
the option of the Company. During the term of the leases, the Company is required to pay, for each vessel, $14,300 per day
accelerating to $17,500 per day in year 11 of the leases. At any time during the term of the lease, the Company has the option to
terminate the leases by giving three months written notice. To cancel one of the leases, the Company would also be required to make a
lump−sum termination payment of the lesser of $10 million if cancelled during years one through eight, $8 million if cancelled during
years nine through twelve, or $7 million if cancelled after twelve years. The cost of the vessel leases and related operation costs of the
vessels are reflected as shipping expense on the accompanying statement of operations.
During periods of non−use, the Company has the option to sublease the vessels to other parties. Revenue associated with subleasing
the vessels is reflected as shipping revenue on the accompanying statement of operations.
Future minimum lease payments under these leases are as follows:
2004
2005
2006
2007
2008
2009 and thereafter
$
12,869,000
12,869,000
12,869,000
12,869,000
12,869,000
88,813,000
$ 153,158,000
7. Bridge Cost Recovery Loss & Third Party Revenue & Cost
The Company uses Marketing to sell the Company’s methanol in the United States. Sales contracts are typically negotiated in the third
quarter of each year for the upcoming year’s production and sold under calendar−year−basis agreements. Accordingly, sales contracts
signed in the fall of 2002 applied to 2003 production. The Plant was shut in for one month during the year due to compressor repairs.
As a result, the Company did not provide methanol to Marketing for sale under the annual sales contracts. Consequently, Marketing
had to purchase methanol on the spot market for resale. The cost of the methanol, net of the price received by Marketing for sales
under the sale commitments, was billed to the Company and is reflected as bridge cost recovery loss on the accompanying statement
of operations.
102
Also as a result of the plant being shut in, the Company purchased methanol on the spot market to meet sales commitments in Europe
that were entered into during 2003 by MG. The cost of the methanol purchased is reflected as cost of third−party purchased methanol
sold and the associated revenue from the sale of this methanol is reflected as sales of purchased third−party methanol on the
accompanying statement of operations.
8. Net Profit Interest
Under the Manufacturing and Marketing Agreement entered into with the Republic of Equatorial Guinea, the Republic is granted a
Net Profit Interest equal to 10% of Net Profits. 2003 was the first year that the Net Profits Interest went into effect.
9. Shipping Revenue & Ship Charter Expense
During 2003 when the plant was shut in the Company subleased its methanol tankers. The revenue earned in subleasing the vessels is
captured as Ship Charter Revenue. The associated cost is captured as Ship Charter Expense.
103
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 fiscal year 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 9a. Controls and Procedures.
Based on the evaluation of the Company’s disclosure controls and procedures by Charles D. Davidson, the Company’s principal
executive officer, and James L. McElvany, the Company’s principal financial officer, as of the end of the period covered by this
report, each of them has concluded that the Company’s disclosure controls and procedures are effective. There were no changes in the
Company’s internal controls over financial reporting that occurred during the fourth quarter 2003 that have materially affected, or are
reasonably likely to materially affect, the Company’s internal controls over financial reporting.
Item 10. Directors and Executive Officers of the Registrant.
PART III
The sections entitled “Election of Directors” and “Information Concerning the Board of Directors” in the Registrant’s proxy statement
for the 2004 annual meeting of stockholders set forth certain information with respect to the directors of the Registrant and certain
committees of the Board of Directors of the Registrant and are 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 2004
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.
The section entitled “Corporate Governance” in the Registrant’s proxy statement for the 2004 annual meeting of stockholders sets
forth certain information required by this item and is incorporated herein by reference.
Item 11. Executive Compensation.
The section entitled “Executive Compensation” in the Registrant’s proxy statement for the 2004 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.
104
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The sections entitled “Security Ownership of Certain Beneficial Owners”, “Security Ownership of Directors and Executive Officers”
and “Equity Compensation Plan Table” in the Registrant’s proxy statement for the 2004 annual meeting of stockholders set forth
certain information with respect to the Registrant’s common stock and are incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions.
The section entitled “Certain Transactions” in the Registrant’s proxy statement for the 2004 annual meeting of stockholders sets forth
certain information with respect to certain relationships and related transactions, and is incorporated herein by reference.
Item 14. Principal Accountant Fees and Services.
The section entitled “Matters Relating to the Independent Auditors” in the Registrant’s proxy statement for the 2004 annual meeting
of stockholders sets forth certain information with respect to principal accountant fees and services, and is incorporated herein by
reference.
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8−K.
PART IV
(a) The following documents are filed as a part of this report:
(1)
(2)
Financial Statements and Financial Statement Schedules and Supplementary Data: These documents are
listed in the Index to Financial Statements in Item 8 hereof.
Exhibits: The exhibits required to be filed by this Item 15 are set forth in the Index to Exhibits
accompanying this report.
(b)
Reports on Form 8−K:
(1)
(2)
On October 29, 2003, the Company furnished on Form 8−K, pursuant to Item 12, Results of Operations and
Financial Condition, and Item 7 (c), Financial Statements and Exhibits, a press release announcing its
financial results for the third quarter of fiscal year 2003.
On December 17, 2003, the Company furnished on Form 8−K, pursuant to Item 12, Results of Operations
and Financial Condition, and Item 7 (c), Financial Statements and Exhibits, a press release updating its
2003 asset disposition program, related discontinued operations and the write−off of an investment in
Vietnam.
105
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 12, 2004
NOBLE ENERGY, INC.
(Registrant)
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
/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
Capacity in which signed
Date
Chairman of the Board, President,
Chief Executive Officer and Director
(Principal Executive Officer)
Senior Vice President,
Chief Financial Officer and Treasurer
(Principal Financial and Accounting Officer)
Director
Director
Director
Director
Director
Director
106
March 12, 2004
March 12, 2004
March 12, 2004
March 12, 2004
March 12, 2004
March 12, 2004
March 12, 2004
March 12, 2004
Exhibit
Number
INDEX TO EXHIBITS
Exhibit **
3.1
— 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
3.3
— 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).
— 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
— First Indenture Supplement relating to $250 million of the Registrant’s 8% Senior Notes Due 2027 dated as of
April 1, 1997 between the Registrant and U.S. Trust Company of Texas, N.A., as Trustee (filed as Exhibit 4.2 to the
Registrant’s Quarterly Report on Form 10−Q for the quarter ended March 31, 1997 and incorporated herein by
reference).
4.4
— 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
4.6
— 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).
— 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).
10.1*
— Restoration of Retirement Income Plan for Certain Participants in the Noble Energy, Inc. Retirement Plan dated
September 21, 1994, effective as of May 19, 1994 (filed as Exhibit 10.5 to the Registrant’s Annual Report on
Form 10−K for the year ended December 31, 1994 and incorporated herein by reference).
10.2*
— Amendment No. 1 to the Restoration of Retirement Income Plan for Certain Participants in the Noble Affiliates
Retirement Plan executed March 26, 2002 (filed as Exhibit 10.2 to the Registrant’s Annual Report on Form 10−K
for the year ended December 31, 2002 and incorporated herein by reference).
107
Exhibit
Number
Exhibit **
10.3 * — Noble Energy, Inc. Restoration Trust effective August 1, 2002 (filed as Exhibit 10.3 to the Registrant’s Annual
Report on Form 10−K for the year ended December 31, 2002 and incorporated herein by reference).
10.4*
— Noble Energy, Inc. Deferred Compensation Plan (formerly known as the Noble Affiliates Thrift Restoration Plan
dated May 9, 1994) as restated effective August 1, 2001 (filed as Exhibit 10.4 to the Registrant’s Annual Report on
Form 10−K for the year ended December 31, 2002 and incorporated herein by reference).
10.5*
— Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended, dated January 27, 2003, and
approved by the stockholders of the Company on April 29, 2003 (filed as Exhibit 10.1 to the Registrant’s Quarterly
Report on Form 10−Q for the quarter ended March 31, 2003 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* — Noble Energy, Inc. Non−Employee Director Fee Deferral Plan dated April 25, 2002 and effective as of
April 23, 2002 (filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10−Q for the quarter ended
March 31, 2002 and incorporated herein by reference).
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
— Guaranty of the Registrant dated October 28, 1982, guaranteeing certain obligations of Samedan (filed as Exhibit
10.12 to the Registrant’s Annual Report on Form 10−K for the year ended December 31, 1993 and incorporated
herein by reference).
— Stock Purchase Agreement dated as of July 1, 1996, between Samedan Oil Corporation and Enterprise Diversified
Holdings Incorporated (filed as Exhibit 2.1 to the Registrant’s Current Report on Form 8−K (Date of Event:
July 31, 1996) dated August 13, 1996 and incorporated herein by reference).
10.14
— Noble Preferred Stock Remarketing and Registration Rights Agreement dated as of November 10, 1999 by and
among the Registrant, Noble Share Trust, The Chase Manhattan Bank, and Donaldson, Lufkin & Jenrette Securities
Corporation (filed as Exhibit 10.15 to the Registrant’s Annual Report on Form 10−K for the year ended
December 31, 1999 and incorporated herein by reference).
10.15* — Letter agreement dated February 1, 2002 between the Registrant and Charles D. Davidson, terminating Mr.
Davidson’s employment agreement and entering into the attached Change of Control Agreement (filed as Exhibit
10.17 to the Registrant’s Annual Report on Form 10−K for the year ended December 31, 2001 and incorporated
herein by reference).
10.16* — 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).
10.17
— 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).
108
Exhibit
Number
10.19
Exhibit **
— 364−day Credit Agreement dated as of November 27, 2002 among the Registrant, as borrower, JPMorgan Chase
Bank, as the administrative agent for the lenders, Wachovia Bank, National Association, as the syndication agent
for the lenders, Societe Generale, Citibank, N.A., Deutsche Bank Ag New York Branch, and The Royal Bank of
Scotland PLC, as co−documentation agents, and certain commercial lending institutions, as lenders, (filed as
Exhibit 10.19 to the Registrant’s Annual Report on Form 10−K for the year ended December 31, 2002 and
incorporated herein by reference).
10.20
— 364−day Credit Agreement dated as of October 30, 2003 among the Registrant, as borrower, JPMorgan Chase
Bank, as the administrative agent for the lenders, Wachovia Bank, National Association, as the syndication agent
for the lenders, Societe Generale, Deutsche Bank Ag New York Branch, and The Royal Bank of Scotland PLC, as
co−documentation agents, and certain commercial lending institutions, as lenders, filed herewith.
12.1
— Computation of ratio of earnings to fixed charges, filed herewith
21
23.1
23.2
31.1
— Subsidiaries, filed herewith.
— Consent of KPMG LLP, filed herewith.
— Consent of Ernst & Young LLP, filed herewith.
— Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes−Oxley Act of
2002 (18 U.S.C. Section 7241), filed herewith.
31.2
— Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes−Oxley Act of 2002
(18 U.S.C. Section 7241), filed herewith.
32.1
— Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes−Oxley Act of
2002 (18 U.S.C. Section 1350), filed herewith.
32.2
— Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes−Oxley Act of 2002
(18 U.S.C. Section 1350), filed herewith.
* 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., 100 Glenborough Drive, Suite
100, Houston, Texas 77067.
109
Exhibit 10.20
[EXECUTION COPY]
364−DAY CREDIT AGREEMENT,
dated as of October 30, 2003
among
NOBLE ENERGY, INC.,
as the Borrower,
JPMORGAN CHASE BANK,
as the Administrative Agent for the Lenders,
WACHOVIA BANK, NATIONAL ASSOCIATION,
as the Syndication Agent for the Lenders,
SOCIÉTÉ GÉNÉRALE,
DEUTSCHE BANK AG NEW YORK BRANCH
and
THE ROYAL BANK OF SCOTLAND PLC,
as the Co−Documentation Agents for the Lenders,
and
CERTAIN COMMERCIAL LENDING INSTITUTIONS,
as the Lenders
J.P. MORGAN SECURITIES INC.,
as Lead Arranger and Sole Bookrunner
364−DAY CREDIT AGREEMENT
THIS 364−DAY CREDIT AGREEMENT, dated as of October 30, 2003 (as may be amended, restated, supplemented or otherwise
modified from time to time, this “Agreement”), is among NOBLE ENERGY, INC., a Delaware corporation (the “Borrower”),
JPMORGAN CHASE BANK (“JPMorgan”), as administrative agent (JPMorgan in such capacity, together with any successor(s)
thereto in such capacity, the “Agent”), WACHOVIA BANK, NATIONAL ASSOCIATION, as syndication agent (in such capacity,
together with any successor(s) thereto in such capacity, the “Syndication Agent”), SOCIÉTÉ GÉNÉRALE, DEUTSCHE BANK AG
NEW YORK BRANCH and THE ROYAL BANK OF SCOTLAND PLC, as co−documentation agents (in such capacity, together
with any successor(s) thereto in such capacity, individually, a “Co−Documentation Agent” and, collectively, the “Co−Documentation
Agents”), and certain commercial lending institutions as are or may become parties hereto (collectively, the “Lenders”).
The parties hereto agree as follows:
ARTICLE I
DEFINITIONS AND ACCOUNTING TERMS
SECTION 1.1
preamble and recitals, shall, except where the context otherwise requires, have the following meanings (such meanings to be equally
applicable to the singular and plural forms thereof):
Defined Terms. The following terms (whether or not underscored) when used in this Agreement, including its
“Affiliate” of any Person means any other Person which, directly or indirectly, controls, is controlled by or is under common control
with such Person (excluding any trustee under, or any committee with responsibility for administering, any Plan). A Person shall be
deemed to be “controlled by” any other Person if such other Person possesses, directly or indirectly, power (a) to vote 20% or more of
the securities (on a fully diluted basis) having ordinary voting power for the election of directors or managing general partners; or (b)
to direct or cause the direction of the management and policies of such Person whether by contract or otherwise.
“Agent” is defined in the preamble and includes each other Person as shall have subsequently been appointed as the successor Agent
pursuant to Section 9.4.
“Agents” means the Agent, the Syndication Agent, the Co−Documentation Agents and any entity identified as a “Senior Managing
Agent” on the signature pages to this Agreement, together with any successors in any such capacities.
“Agreement” means, on any date, this 364−Day Credit Agreement as originally in effect on the Effective Date and as thereafter from
time to time amended, supplemented, amended and restated, or otherwise modified and in effect on such date.
“Administrative Questionnaire” means an Administrative Questionnaire in a form supplied by the Agent.
“Applicable Facility Fee Rate” means the number of basis points per annum (based on a year of 360 days) set forth below based on the
Applicable Rating Level on such date:
Applicable Rating Level
Level I
Level II
Level III
Level IV
Level V
Applicable Facility Fee Rate
12.5
15.0
17.5
20.0
25.0
In the event that any outstanding Revolving Loans are converted to Term Loans pursuant to Section 2.1.2, then the Applicable Facility
Fee Rate shall be increased by 25.0 basis points. Changes in the Applicable Facility Fee Rate will occur automatically without prior
notice. The Agent will give notice promptly to the Borrower and the Lenders of changes in the Applicable Facility Fee Rate.
“Applicable Margin” means on any date and with respect to each Eurodollar Loan the number of basis points per annum set forth
below based on the Applicable Rating Level on such date:
Applicable Rating
Level
Level I
Level II
Level III
Level IV
Level V
Utilization less than or
equal to 25%
Utilization greater than
25%
62.5
72.5
82.5
105.0
125.0
75.0
85.0
95.0
130.0
150.0
In the event that any outstanding Revolving Loans are converted to Term Loans pursuant to Section 2.1.2, then the Applicable Margin
as to such Loans shall be increased by 25.0 basis points. Changes in the Applicable Margin will occur automatically without prior
notice. The Agent will give notice promptly to the Borrower and the Lenders of changes in the Applicable Margin.
“Applicable Rating Level” means (i) at any time that Moody’s and S&P have the equivalent rating or split ratings of not more than
one rating differential of the Borrower’s senior unsecured long−term debt, the level set forth in the chart below under the heading
“Applicable Rating Level” opposite the rating under the heading “Moody’s” or “S&P” which is the higher of
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the two if split ratings or opposite the ratings under the headings “Moody’s” and “S&P” if equivalent, and (ii) at any time that
Moody’s and S&P have split ratings of more than one rating differential of the Borrower’s senior unsecured long−term debt, the level
set forth in the chart below under the “Applicable Rating Level” opposite the rating under the heading “Moody’s” or “S&P” which is
one notch higher than the lower of the two ratings.
Applicable Rating Level
Level I
Level II
Level III
Level IV
Level V
Moody’s
>A3
Baa1
Baa2
Baa3
A−
BBB+
BBB
BBB−
“ means a rating equal to or more favorable than; “<“ means a rating equal to or less favorable
than; “>“ means a rating greater than; “<“ means a rating less than; (ii) if a rating for the Borrower’s senior unsecured long−term debt
is not available from one of the Rating Agencies, the Applicable Rating Level will be based on the rating of the other Rating Agency;
(iii) if ratings for the Borrower’s senior unsecured long−term debt is available from neither S&P nor Moody’s, Level V shall be
deemed applicable; (iv) if determinative ratings shall change (other than as a result of a change in the rating system used by any
applicable Rating Agency) such that a change in Applicable Rating Level would result, such change shall effect a change in
Applicable Rating Level as of the day on which it is first announced by the applicable Rating Agency, and any change in the
Applicable Margin or percentage used in calculating fees due hereunder shall apply commencing on the effective date of such change
and ending on the date immediately preceding the effective date of the next such change; and (v) if the rating system of any of the
Rating Agencies shall change prior to the date all obligations hereunder have been paid and the Commitments canceled, the Borrower
and the Lenders shall negotiate in good faith to amend the references to specific ratings in this definition to reflect such changed rating
system, and pending such amendment, if no Applicable Rating Level is otherwise determinable based upon the foregoing, Level V
shall apply.
“Arranger” means J.P. Morgan Securities Inc., in its capacity as sole lead arranger.
“Assignee Lender” is defined in Section 10.10.1.
“Authorized Officer” means, relative to the Borrower, the President, any Senior Vice President, the Treasurer or the Secretary of the
Borrower, or any other officer of the Borrower specified as such to the Agent in writing by any of the aforementioned officers of the
Borrower.
“Base Rate” means, on any date and with respect to all Base Rate Loans, a fluctuating rate of interest per annum equal to the higher of
(a) the rate of interest most recently announced
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by JPMorgan at its Domestic Office as its base rate for Dollar loans; and (b) the Federal Funds Rate most recently determined by the
Agent plus ½%. The Base Rate is not necessarily intended to be the lowest rate of interest determined by JPMorgan in connection
with extensions of credit. Changes in the rate of interest on that portion of any Loans maintained as Base Rate Loans will take effect
simultaneously with each change in the Base Rate. The Agent will give notice promptly to the Borrower and the Lenders of changes
in the Base Rate.
“Base Rate Loan” means a Loan bearing interest at a fluctuating rate determined by reference to the Base Rate.
“Borrower” is defined in the preamble, and includes its permitted successors and assigns.
“Borrowing” means any extension of credit (as opposed to any continuation or conversion thereof) made by the Lenders by way of
Loans.
“Borrowing Date” means a date on which a Borrowing is made hereunder.
“Borrowing Request” means a loan request and certificate duly executed by an Authorized Officer of the Borrower, substantially in
the form of Exhibit 2.5 hereto.
“Business Day” means (a) any day which is neither a Saturday or Sunday nor a legal holiday on which banks are authorized or
required to be closed in New York, New York or Houston, Texas; and (b) relative to the making, continuing, prepaying or repaying of
any Eurodollar Borrowing, any day on which dealings in Dollars are carried on in the London and New York Eurodollar interbank
market.
“Capitalization” means the sum, at any time outstanding and without duplication, of (i) Debt plus (ii) Stockholders’ Equity.
“Capitalized Lease Liabilities” means all monetary obligations of the Borrower or any of its Subsidiaries under any leasing or similar
arrangement which, in accordance with GAAP, would be classified as capitalized leases, and, for purposes of this Agreement and each
other Loan Document, the amount of such obligations shall be the capitalized amount thereof, determined in accordance with GAAP,
and the stated maturity thereof shall be the date of the last payment of rent or any other amount due under such lease prior to the first
date upon which such lease may be terminated by the lessee without payment of a penalty.
“CERCLA” means the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended.
“Change in Control” means the acquisition by any Person, or two or more Persons acting in concert, of beneficial ownership (within
the meaning of Rule 13d−3 of the Securities and Exchange Commission under the Securities Exchange Act of 1934) of 30% or more
of the outstanding shares of voting stock of the Borrower.
“Code” means the Internal Revenue Code of 1986, as amended, reformed or otherwise modified from time to time.
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“Co−Documentation Agent” and “Co−Documentation Agents” are defined in the preamble.
“Commitment” means, as to any Lender, the obligation, if any, of such Lender to make Loans pursuant to Section 2.1.1 or Section
2.1.2 of this Agreement in an aggregate principal amount at any one time outstanding up to but not exceeding the amount, if any, set
forth opposite such Lender’s name on Schedule II, as the same may be reduced or adjusted from time to time in accordance with this
Agreement, including Sections 2.3.
“Commitment Amount” means, on any date, $300,000,000, as such amount may be reduced from time to time in accordance with this
Agreement, including Section 2.3.
“Commitment Termination Event” means (a) the occurrence of any Event of Default described in clauses (a) through (e) of Section
8.1.9; or (b) the occurrence and continuance of any other Event of Default and either (i) the declaration of the Loans to be due and
payable pursuant to Section 8.3, or (ii) in the absence of such declaration, the giving of notice by the Agent, acting at the direction of
the Required Lenders, to the Borrower that the Commitments have been terminated.
“Continuation/Conversion Notice” means a notice of continuation or conversion and certificate duly executed by an Authorized
Officer of the Borrower, substantially in the form of Exhibit 2.6 hereto.
“Controlled Group” means all members of a controlled group of corporations and all members of a controlled group of trades or
businesses (whether or not incorporated) under common control which, together with the Borrower, are treated as a single employer
under Section 414(b) or 414(c) of the Code or Section 4001 of ERISA.
“Debt” means the consolidated Indebtedness of the Borrower and its Subsidiaries.
“Default” means any condition, occurrence or event which, after notice or lapse of time or both, would constitute an Event of Default.
“Default Margin” means two percent (2%).
“Disclosure Schedule” means the Disclosure Schedule attached hereto as Schedule I, as it may be amended, supplemented or
otherwise modified from time to time by the Borrower with the written consent of the Agent and the Required Lenders.
“Dollar” and the sign “$” mean lawful money of the United States.
“Domestic Office” means, relative to any Lender, the office of such Lender designated as such in its Administrative Questionnaire or
designated in the Lender Assignment Agreement or such other office of a Lender (or any successor or assign of such Lender) within
the United States as may be designated from time to time by notice from such Lender, as the case may be, to each other Person party
hereto.
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“EBITDAX” means, for any period, the sum of (i) the consolidated net income of the Borrower and its Subsidiaries for such period
before non−cash non−recurring items, gains or losses on dispositions of assets and the cumulative effect of changes in accounting
principles plus (ii) to the extent included in the determination of such income, the consolidated charges for such period for interest,
depreciation, depletion, amortization and exploration expenses plus (or, if there is a benefit from income taxes, minus) (iii) to the
extent included in the determination of such income, the amount of the provision for or benefit from income taxes.
“EDC” means Energy Development Corporation, a New Jersey corporation, and its permitted successors and assigns.
“Effective Date” means the date on which the conditions specified in Article V are satisfied (or waived in accordance with Section
10.1).
“Environmental Law” means any federal, state, or local statute, or rule or regulation promulgated thereunder, any judicial or
administrative order or judgment to which the Borrower or any Subsidiary is party or which are applicable to the Borrower or any
Subsidiary (whether or not by consent), and any provision or condition of any governmental permit, license or other operating
authorization, relating to protection of the environment, persons or the public welfare from actual or potential exposure for the effects
of exposure to any actual or potential release, discharge, spill or emission (whether past or present) of, or regarding the manufacture,
processing, production, gathering, transportation, importation, use, treatment, storage or disposal of, any chemical, raw material,
pollutant, contaminant or toxic, corrosive, hazardous, or non−hazardous substance or waste, including petroleum.
“ERISA” means the Employee Retirement Income Security Act of 1974, as amended, and any successor statute of similar import,
together with the regulations thereunder, in each case as in effect from time to time. References to sections of ERISA also refer to any
successor sections.
“Eurodollar Borrowing” means a borrowing hereunder consisting of the aggregate amount of the several Eurodollar Loans made by all
or some of the Lenders to the Borrower, at the same time, at the same interest rate and for the same Interest Period.
“Eurodollar Loan” means a Loan bearing interest, at all times during an Interest Period applicable to such Loan, at a fixed rate of
interest determined by reference to the Eurodollar Rate.
“Eurodollar Office” means, relative to any Lender, the office of such Lender designated as such in its Administrative Questionnaire or
designated in the Lender Assignment Agreement or such other office of a Lender as designated from time to time by notice from such
Lender to the Borrower and the Agent, whether or not outside the United States, which shall be making or maintaining Eurodollar
Loans of such Lender hereunder.
“Eurodollar Rate” means, relative to any Interest Period for Eurodollar Loans, the rate appearing on Page 3750 of the Telerate Service
(or on any successor or substitute page of such Service, or any successor to or substitute for such Service, providing rate quotations
comparable to those currently provided on such page of such Service, as determined by the Agent from time
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to time for purposes of providing quotations of interest rates applicable to dollar deposits in the London interbank market) at
approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period, as the rate for dollar
deposits with a maturity comparable to such Interest Period. In the event that such rate is not available at such time for any reason,
then the “Eurodollar Rate” with respect to such Eurodollar Loan for such Interest Period shall be the rate at which dollar deposits of
$5,000,000 and for a maturity comparable to such Interest Period are offered by the principal London office of the Agent in
immediately available funds in the London interbank market at approximately 11:00 a.m., London time, two Business Days prior to
the commencement of such Interest Period
“Event of Default” is defined in Section 8.1.
“Existing Credit Facility” means that certain 364−Day Credit Agreement, dated as of November 27, 2002, among the Borrower, JP
Morgan Chase Bank, as administrative agent, and the lenders and the agents party thereto, and the other agreements or instruments
executed and delivered in connection with, or as security for the payment or performance of the obligations thereunder, as such
agreements may have been amended, supplemented or restated from time to time.
“Facility” is defined in Section 2.1.
“Federal Funds Rate” means, for any day, the average rate quoted to the Agent at approximately 11:00 a.m. (Central time) on such day
(or, if such day is not a Business Day, on the next preceding Business Day) for overnight Federal Funds transactions arranged by New
York Federal Funds brokers selected by the Agent.
“Fee Letter” is defined in Section 3.3.2.
“Fiscal Quarter” means any quarter of a Fiscal Year.
“Fiscal Year” means any period of twelve consecutive calendar months ending on December 31.
“Five Year Credit Agreement” means that certain Credit Agreement, dated as of November 30, 2001, among the Borrower (formerly
known as Noble Affiliates, Inc.), JPMorgan Chase Bank, as administrative agent, and the lenders and the agents party thereto, as such
agreement may be amended, supplemented or restated from time to time.
“F.R.S. Board” means the Board of Governors of the Federal Reserve System or any successor thereto.
“GAAP” is defined in Section 1.4.
“Guaranteed Liability” means any agreement, undertaking or arrangement by which any Person guarantees, endorses or otherwise
becomes or is contingently liable upon (by direct or indirect agreement, contingent or otherwise, to provide funds for payment, to
supply funds to, or otherwise to invest in, a debtor, or otherwise to assure a creditor against loss) the Indebtedness of any other Person
(other than by endorsements of instruments in the course of collection), or
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guarantees the payment of dividends or other distributions upon the shares of any other Person. The amount of any Person’s
Guaranteed Liability shall be the lesser of (i) the limitation on such Person’s liability , if any, set forth in such agreement, undertaking
or arrangement or (ii) the outstanding principal amount of the Indebtedness guaranteed thereby. Guaranteed Liabilities shall exclude
any act or agreement in connection with any financing of a project owned by any Person that either (A) guarantees performance of the
acquisition, improvement, installation, design, engineering, construction, development, completion, maintenance or operation of, or
otherwise affects any such act in respect of, all or a portion of the project that is financed, except during any period, and then only to
the extent, that such act or agreement is a guarantee of payment of such financing or (B) the obligation to pay or perform under which
is contingent upon the occurrence of an event or condition which has not occurred, other than notice, the passage of time or such
financing or any part thereof becoming due; provided, however, to the extent that any partial payment is required to be made under
any such act or agreement providing for a contingent payment obligation as described in clause (B) above, “Guaranteed Liability”
shall be deemed to include an amount equal to four (4) times such amount required to be paid during the Fiscal Quarter most recently
ended, up to the full amount of the Guaranteed Liability as specified in the immediately preceding sentence.
“Hazardous Material” means: (i) any “hazardous substance”, as defined by CERCLA; (ii) any “hazardous waste”, as defined by the
Resource Conservation and Recovery Act, as amended; (iii) any petroleum, crude oil or any fraction thereof; (iv) any hazardous,
dangerous or toxic chemical, material, waste or substance within the meaning of any Environmental Law; (v) any radioactive material,
including any naturally occurring radioactive material, and any source, special or by−product material as defined in 42 U.S.C. § 2011
et. seq., and any amendments or reauthorizations thereof; (vi) asbestos−containing materials in any form or condition; or (vii)
polychlorinated biphenyls in any form or condition.
“Hedging Obligations” means, with respect to any Person, all liabilities of such Person under derivative contracts, including interest
rate or commodity swap agreements, interest rate or commodity cap agreements and interest rate or commodity collar agreements, and
all similar agreements or arrangements.
“Herein”, “hereof”, “hereto”, “hereunder” and similar terms contained in this Agreement or any other Loan Document refer to this
Agreement or such other Loan Document, as the case may be, as a whole and not to any particular Section, paragraph or provision of
this Agreement or such other Loan Document.
“Impermissible Qualification” means, relative to the opinion or certification of any independent public accountant as to any financial
statement of the Borrower, any qualification or exception to such opinion or certification (a) which is of a “going concern” or similar
nature; (b) which relates to the limited scope of examination of matters relevant to such financial statement; or (c) which relates to the
treatment or classification of any item in such financial statement and which, as a condition to its removal, would require an
adjustment to such item the effect of which would be to cause the Borrower to be in default of any of its obligations under Section
7.2.4.
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“Including” means including without limiting the generality of any description preceding such term.
“Indebtedness” of any Person means, without duplication: (a) all obligations of such Person for borrowed money and all obligations of
such Person evidenced by bonds, debentures, notes or other similar instruments; (b) all obligations relative to banker’s acceptances
issued for the account of such Person; (c) all obligations of such Person as lessee under leases which have been or should be, in
accordance with GAAP, recorded as Capitalized Lease Liabilities; (d) all obligations of such Person to pay the deferred purchase price
of property or services (except accounts payable arising in the ordinary course of business), (e) Indebtedness of another Person of the
type described in clauses (a), (b), (c) or (d) above secured by a Lien on property owned or being purchased by such Person (including
indebtedness arising under conditional sales or other title retention agreements), whether or not such Indebtedness shall have been
assumed by such Person or is limited in recourse (such Indebtedness being the lesser of (i) the value of such property on the books of
such Person or (ii) the outstanding principal amount of such Indebtedness); and (f) all Guaranteed Liabilities of such Person in respect
of any of the foregoing. For all purposes of this Agreement, the Indebtedness of any Person shall include the Indebtedness of any
partnership or joint venture in which such Person is a general partner or a joint venturer except to the extent that such Indebtedness by
its terms is expressly non−recourse to such general partner or joint venturer.
“Indemnified Liabilities” is defined in Section 10.4.
“Indemnified Parties” is defined in Section 10.4.
“Information” is defined in Section 10.12.
“Interest Period” means, with respect to Eurodollar Borrowings, the period beginning on (and including) the date on which such
Eurodollar Borrowing is made or continued as, or converted into, a Eurodollar Borrowing pursuant to Section 2.5 or 2.6 and shall end
on (but exclude) the day which numerically corresponds to such date one, two, three or six months thereafter (or, if such month has no
numerically corresponding day, on the last Business Day of such month), as the Borrower may select in its relevant notice pursuant to
Section 2.5, provided, however, that (a) the Borrower shall not be permitted to select Interest Periods to be in effect at any one time
which have expiration dates occurring on more than five different dates; (b) Interest Periods commencing on the same date for Loans
comprising part of the same Borrowing shall be of the same duration; (c) if such Interest Period would otherwise end on a day which
is not a Business Day, such Interest Period shall end on the next following Business Day (unless, if such Interest Period applies to
Eurodollar Loans, such next following Business Day is the first Business Day of a calendar month, in which case such Interest Period
shall end on the Business Day next preceding such numerically corresponding day); and (d) no Interest Period may end later than the
Maturity Date.
“JPMorgan” is defined in the preamble, and includes its successors and assigns.
“Law” means any law (including, without limitation, any zoning law or ordinance or any Environmental Law), statute, rule,
regulation, ordinance, order, directive, code, interpretation,
9
judgment, decree, injunction, writ, determination, award, permit, license, authorization, direction, requirement or decision of and
agreement with or by any government or governmental department, commission, board, court, authority, agency, official or officer,
domestic or foreign.
“Lender Affiliate” means, (a) with respect to any Lender, (i) an Affiliate of such Lender or (ii) any entity (whether a corporation,
partnership, trust or otherwise) that is engaged in making, purchasing, holding or otherwise investing in bank loans and similar
extensions of credit in the ordinary course of its business and is administered or managed by a Lender or an Affiliate of such Lender
and (b) with respect to any Lender that is a fund which invests in bank loans and similar extensions of credit, any other fund that
invests in bank loans and similar extensions of credit and is managed by the same investment advisor as such Lender or by an Affiliate
of such investment advisor.
“Lender Assignment Agreement” means a Lender Assignment Agreement substantially in the form of Exhibit 10.10 hereto.
“Lenders” means the financial institutions listed on the signature pages hereto and their respective successors and assigns in
accordance with Section 10.10 (including any commercial lending institution becoming a party hereto pursuant to a Lender
Assignment Agreement) or otherwise by operation of law.
“Lien” means any security interest, mortgage, pledge, hypothecation, assignment, deposit arrangement, encumbrance, lien (statutory
or otherwise), charge against or interest in property to secure payment of a debt or the performance of an obligation.
“Loan” shall mean the Revolving Loans and the Term Loans.
“Loan Advances” means the Loans of the same Type and, in the case of Eurodollar Loans, having the same Interest Period made by
all Lenders on the same Business Day and pursuant to the same Borrowing Request in accordance with Section 2.1.
“Loan Documents” means this Agreement, each Borrowing Request, each Borrowing Notice, the Fee Letter, any note, together in
each case with all exhibits, schedules and attachments thereto, and all other agreements and instruments from time to time executed
and delivered by the Borrower or any of its Subsidiaries pursuant to or in connection with any of the foregoing.
“Margin Stock” means “margin stock” within the meaning of Regulation U.
“Material Adverse Effect” means a material adverse effect on (i) the business, property, financial condition or results of operations of
the Borrower and its consolidated Subsidiaries (taken as a whole) or (ii) the ability of the Borrower to perform its payment obligations
under any of the Loan Documents.
“Maturity Date” shall mean the earlier of:
(a)
the date occurring 364 days after the Term Commitment Termination Date; and
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(c)
the date on which the Obligations have become due and payable in full pursuant to the terms of Article VIII.
“Moody’s” means Moody’s Investors Service, Inc. and any successor thereto that is a nationally−recognized rating agency.
“Obligations” means all obligations (monetary or otherwise) of the Borrower arising under or in connection with this Agreement and
each other Loan Document.
“Organic Document” means, relative to the Borrower, its certificate of incorporation, its by−laws and all shareholder agreements,
voting trusts and similar arrangements applicable to any of its authorized shares of capital stock.
“Participant” is defined in Section 10.10.
“Payment Date” is defined in Section 3.2.3.
“Payment Office” means the principal office of the Administrative Agent, presently located at JPMorgan Chase Bank, Agency
Services, One Chase Manhattan Plaza, 8th Floor, New York, NY 10081, Attention: Muniram Appanna.
“PBGC” means the Pension Benefit Guaranty Corporation and any entity succeeding to any or all of its functions under ERISA.
“Pension Plan” means a “pension plan”, as such term is defined in section 3(2) of ERISA, which is subject to Title IV of ERISA (other
than a multiemployer plan as defined in section 4001(a)(3) of ERISA), and to which the Borrower or any corporation, trade or
business that is, along with the Borrower, a member of a Controlled Group, may have liability, including any liability by reason of
having been a substantial employer within the meaning of section 4063 of ERISA at any time during the preceding five years, or by
reason of being deemed to be a contributing sponsor under section 4069 of ERISA.
“Percentage” means, relative to any Lender, the percentage set forth in Schedule II attached hereto or set forth in the most recent
Lender Assignment Agreement executed by such Lender, as such percentage may be adjusted from time to time pursuant to Lender
Assignment Agreements executed by such Lender and its Assignee Lenders and delivered pursuant to Section 10.10.
“Person” means any natural person, corporation, partnership, firm, association, trust, government, governmental agency or any other
entity, whether acting in an individual, fiduciary or other capacity.
“Plan” means any Pension Plan or Welfare Plan.
“Quarterly Payment Date” means the last day of each March, June, September, and December or, if any such day is not a Business
Day, the next succeeding Business Day.
“Rating Agency” means either of S&P or Moody’s.
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“Regulation U” means any of Regulations T, U or X of the Board of Governors of the Federal Reserve System of the United States of
America (the “Board”) from time to time in effect and shall include any successor or other regulations or official interpretations of the
Board or any successor Person relating to the extension of credit for the purpose of purchasing or carrying Margin Stock and which is
applicable to member banks of the Federal Reserve System or any successor Person.
“Release” means a “release”, as such term is defined in CERCLA.
“Required Lenders” means Lenders in the aggregate holding greater than 50% of the aggregate unpaid principal amount of the
outstanding Borrowings and if no Borrowings are outstanding, Lenders having greater than 50% of the then Total Commitment.
“Resource Conservation and Recovery Act” means the Resource Conservation and Recovery Act, 42 U.S.C. Section 690, et seq., as in
effect from time to time.
“Restricted Subsidiary” means any Subsidiary that is not an Unrestricted Subsidiary.
“Revolving Commitment” shall mean, as to any Lender, the obligation, if any, of such Lender to make Loans pursuant to Sections
2.1.1 of this Agreement in an aggregate principal amount at any one time outstanding up to but not exceeding the amount, if any, set
forth opposite such Lender’s name on Schedule III, as the same may be reduced, increased or adjusted from time to time in accordance
with this Agreement, including Sections 2.3.
“Revolving Commitment Termination Date” shall mean the earliest of:
(a)
(b)
(c)
VIII.
October 28, 2004;
the date on which the Commitment Amount is terminated in full or reduced to zero pursuant to the terms of Section 2.3; and
the date on which the Revolving Commitments are terminated in full and reduced to zero pursuant to the terms of Article
“Revolving Loans” shall mean the loans provided for in Section 2.1.1 hereof.
“S&P” means Standard & Poor’s Ratings Group and any successor thereto that is a nationally−recognized rating agency.
“Solvent” means, with respect to any Person at any time, a condition under which: a) the fair saleable value of such Person’s assets is,
on the date of determination, greater than the total amount of such Person’s liabilities (including contingent and unliquidated
liabilities) at such time; b) such Person is able to pay all of its liabilities as such liabilities mature; and c) such Person does not have
unreasonably small capital with which to conduct its business. For purposes of this definition (i) the amount of a Person’s contingent
or unliquidated liabilities at any time shall be that amount which, in light of all the facts and circumstances then existing, represents
the amount which can reasonably be expected to become an actual or matured liability; (ii) the “fair saleable value” of an asset shall
be the amount which may be realized
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within a reasonable time either through collection or sale of such asset at its regular market value; and (iii) the “regular market value”
of an asset shall be the amount which a capable and diligent business person could obtain for such asset from an interested buyer who
is willing to purchase such asset under ordinary selling conditions.
“Stockholders’ Equity” means, as of the time of any determination thereof is to be made, shareholders’ equity of the Borrower and its
consolidated Subsidiaries determined in accordance with GAAP plus the absolute cumulative amount by which such stockholders’
equity shall have been reduced by reason of non−cash write downs of oil and gas assets from time to time after the Effective Date.
“Subsidiary” means any subsidiary of the Borrower.
“subsidiary” means, with respect to any Person, (a) any corporation, limited liability company or other business entity of which more
than 50% of the outstanding equity interests having ordinary voting power to elect a majority of the board of directors (or persons
performing similar functions) of such corporation, limited liability company or other business entity (irrespective of whether at the
time equity interests of any other class or classes of such corporation, limited liability company or other business entity shall or might
have voting power upon the occurrence of any contingency) is at the time directly or indirectly owned by such Person, by such Person
and one or more other Subsidiaries of such Person, or by one or more other Subsidiaries of such Person and (b) any partnership of
which such Person, such Person and one or more other Subsidiaries of such Person, or one or more other Subsidiaries of such Person
holds more than 50% of the outstanding general partner interests.
“Syndication Agent” is defined in the preamble.
“Taxes” is defined in Section 4.6.
“Term Commitment” shall mean, as to any Lender, such Lender’s obligation to make Term Loans pursuant to Section 2.1.2 of this
Agreement in an aggregate principal amount equal to the lesser of (i) the aggregate Revolving Loans outstanding to such Lender as of
the Revolving Commitment Termination Date or (ii) such Lender’s Revolving Commitment in effect as of the Revolving
Commitment Termination Date.
“Term Commitment Termination Date” shall mean the earlier of:
(a)
the Business Day after the Revolving Commitment Termination Date; and
(b)
Article VIII.
the date on which the Revolving Commitments otherwise are terminated in full and reduced to zero pursuant to the terms of
Upon the occurrence of any event described in clause (b), the Term Commitments shall terminate automatically and without any
further action.
“Term Loans” shall mean the loans provided for in Section 2.1.2 hereof.
13
“364−Day Total Commitment” means (i) on or prior to the Revolving Commitment Termination Date, the then effective Total
Commitment under this Agreement, or (ii) after the Revolving Commitment Termination Date, the then outstanding principal amount
of Term Loans under this Agreement.
“Total Asset Value” means, at any time with respect to any assets, the book value of such assets determined in accordance with
GAAP.
“Total Commitment” means the aggregate of all the Lenders’ Commitments.
“Total Debt to Capitalization Ratio” means the ratio of (a) Debt to (b) Capitalization.
“Total Interest Expense” means with respect to any period for which a determination thereof is to be made, interest expense of the
Borrower and its Subsidiaries on a consolidated basis as determined in accordance with GAAP.
“Type” means, relative to any Loan, the portion thereof, if any, being maintained as a Base Rate Loan or a Eurodollar Loan.
“United States” or “U.S.” means the United States of America, its fifty States and the District of Columbia.
“Unrestricted Subsidiary” means any Subsidiary that is designated on Schedule 6.8 as such or which the Borrower has designated in
writing to the Agent to be an Unrestricted Subsidiary pursuant to Section 7.1.8, and, in either case, which the Borrower has not
designated to be a Restricted Subsidiary pursuant to Section 7.1.8.
“Utilization” means, at any time, the ratio (expressed as a percentage) of (i) the sum of (A) the outstanding principal amount of Loans
under this Agreement plus (B) the outstanding principal amount of “Loans” (as such term is defined in the Five Year Credit
Agreement) under the Five Year Credit Agreement to (ii) the sum of (X) 364−Day Total Commitment plus (Y) the then effective
Total Commitment under the Five Year Credit Agreement.
“Welfare Plan” means a “welfare plan”, as such term is defined in section 3(1) of ERISA.
Use of Defined Terms. Unless otherwise defined or the context otherwise requires, terms for which meanings are
SECTION 1.2
provided in this Agreement shall have such meanings when used in the Disclosure Schedule and in each Borrowing Request,
Continuation/Conversion Notice, notice and other communication delivered from time to time in connection with this Agreement or
any other Loan Document.
Cross−References. Unless otherwise specified, references in this Agreement and in each other Loan Document to
SECTION 1.3
any Article or Section are references to such Article or Section of this Agreement or such other Loan Document, as the case may be,
and, unless otherwise specified, references in any Article, Section or definition to any clause are references to such clause of such
Article, Section or definition.
14
SECTION 1.4
Accounting and Financial Determinations. Unless otherwise specified, all accounting terms used herein or in any
other Loan Document shall be interpreted, all accounting determinations and computations hereunder or thereunder (including under
Section 7.2.3) shall be made, and all financial statements required to be delivered hereunder or thereunder shall be prepared in
accordance with, those generally accepted accounting principles (“GAAP”) applied in the preparation of the financial statements
referred to in Section 6.5.
ARTICLE II
THE FACILITY AND BORROWING PROCEDURES
SECTION 2.1
Facility. The Lenders grant to the Borrower a credit facility (the “Facility”) pursuant to which, and upon the terms
and subject to the conditions herein set out and provided that no Default or Event of Default has occurred and is continuing from time
to time on any Business Day, each Lender severally agrees to make Loans in U.S. Dollars to the Borrower equal to such Lender’s
Percentage of the aggregate amount of Loans requested by the Borrower to be made on such day.
Revolving Loans. From time to time on or after the date hereof and prior to the Revolving Commitment
SECTION 2.1.1
Termination Date, each Lender shall make Revolving Loans under this Section to the Borrower in an aggregate principal amount at
any one time outstanding up to but not exceeding such Lender’s Revolving Commitment. Subject to the conditions herein, any such
Loan repaid prior to the Revolving Commitment Termination Date may be reborrowed pursuant to the terms of this Agreement
Term Loans. Subject to the terms and conditions of this Agreement, on the Revolving Commitment Termination
SECTION 2.1.2
Date (unless such date shall occur as a result of clause (c) of the definition thereof), each Lender will make one Term Loan to the
Borrower up to but not exceeding such Lender’s Term Commitment. No amounts paid or prepaid with respect to the Term Loan may
be reborrowed. Eurodollar Loans for which the Interest Period shall not have terminated as of the Revolving Commitment
Termination Date shall be continued as Eurodollar Loans for the applicable Interest Period and Base Rate Loans shall be continued as
Base Rate Loans after the Revolving Commitment Termination Date, in each case subject to further elections pursuant to Section 2.6.
Any principal repayments received on the Revolving Commitment Termination Date for Revolving Loans not converted into Term
Loans shall be applied first to Base Rate Loans and, after Base Rate Loans have been paid in full, to Eurodollar Loans, unless the
Borrower shall have otherwise instructed the Agent in writing. Upon a Lender making such Term Loan, its Term Commitment shall
terminate and it shall have no further Revolving Commitment to make Revolving Loans or Term Commitment to make Term Loans.
Availability of Facility. No Lender shall be permitted or required to make (i) any Loan if, after giving effect
SECTION 2.1.3
thereto, the aggregate outstanding principal amount of all Loans of all Lenders would exceed the Commitment Amount, or (ii) any
Loan if, after giving effect thereto, the aggregate amount of all Loans of such Lender would exceed the Lender’s Percentage of the
Commitment Amount.
SECTION 2.2
[Intentionally Omitted]
15
Reduction of Commitment Amount. The Borrower may, from time to time on any Business Day occurring after
SECTION 2.3
the Effective Date, voluntarily reduce the amount of the Commitment Amount; provided, however, that all such reductions shall
require at least three Business Days’ prior notice to the Agent and be permanent, and any partial reduction of the Commitment
Amount shall be in a minimum amount of $10,000,000 and in an integral multiple of $1,000,000; and provided further that, prior to
the Revolving Commitment Termination Date, the Borrower shall not reduce the Commitment Amount if, after giving effect to any
concurrent prepayment of the Loans in accordance with Section 3.1, the aggregate principal amount of Loans outstanding will exceed
the aggregate of the Revolving Commitments.
Base Rate Loans and Eurodollar Loans. Subject to the terms and conditions set forth in Article V, each Loan shall
SECTION 2.4
be either a Eurodollar Loan or a Base Rate Loan as the Borrower may request, it being understood that Loans made to the Borrower
on any date may be either Eurodollar Loans or Base Rate Loans or a combination thereof. As to any Eurodollar Loan, each Lender
may, if it so elects, fulfill its commitment to make such Eurodollar Loan by causing its Eurodollar Office to make such Eurodollar
Loan; provided, however, that in such event the obligation of the Borrower to repay such Eurodollar Loan nevertheless shall be to
such Lender and shall be deemed to be held by such Lender for the account of such Eurodollar Office.
Borrowing Procedures for Loans. The Borrower shall give the Agent prior written or telegraphic notice pursuant
SECTION 2.5
to a Borrowing Request (in substantially the form of Exhibit 2.5 hereto) of each proposed Borrowing or continuation, and as to
whether such Borrowing or continuation is to be of Revolving Loans or Term Loans and Base Rate Loans or Eurodollar Loans, as
follows:
Base Rate Loans. The Agent shall receive written or telegraphic notice from the Borrower on or before 2:00 p.m.
SECTION 2.5.1
Central time one (1) Business Day prior to the date of such Borrowing and amount of such Borrowing (which shall be in a minimum
amount of $5,000,000 and an integral multiple of $1,000,000), and the Agent shall advise each Lender thereof promptly thereafter.
Not later than 10:00 a.m., Central time, on the date specified in such notice for such Borrowing, each Lender shall provide to the
Agent at the Payment Office, same day or immediately available funds covering such Lender’s Percentage of the requested Base Rate
Loan. Upon fulfillment of the applicable conditions set forth in Article V with respect to such Base Rate Loan, the Agent shall make
available to the Borrower the proceeds of each Base Rate Loan (to the extent received from the Lenders) by wire transfer of such
proceeds to such account(s) as the Borrower shall have specified in the Borrowing Request.
Eurodollar Loans. The Agent shall receive written or telegraphic notice pursuant to a Borrowing Request from the
SECTION 2.5.2
Borrower on or before 10:00 a.m. Central time, at least three (3) Business Days prior to the date requested for each proposed
Borrowing or continuation of a Eurodollar Loan, of the date of such Borrowing or continuation, as the case may be, the amount of
such Borrowing or continuation, as the case may be (which shall be in a minimum amount of $5,000,000 and an integral multiple of
$1,000,000), and the duration of the initial Eurodollar Interest Period with respect thereto, and the Agent shall advise each Lender
thereof promptly thereafter. Not later than 10:00 a.m., Central time, on the date specified in such notice for such Borrowing, each
Lender shall provide to the Agent at the Payment Office, same
16
day or immediately available funds covering such Lender’s Percentage of the requested Eurodollar Loan. Upon fulfillment of the
applicable conditions set forth in Article V with respect to such Eurodollar Loan, the Agent shall make available to the Borrower the
proceeds of each Eurodollar Loan (to the extent received from the Lenders) by wire transfer of such proceeds to such account(s) as the
Borrower shall have specified in the Borrowing Request.
Continuation and Conversion Elections. By delivering a Continuation/Conversion Notice to the Agent on or
SECTION 2.6
before 10:00 a.m., Central time, on a Business Day, the Borrower may from time to time irrevocably elect, on not less than three (3)
nor more than five (5) Business Days’ notice that all, or any portion in an aggregate minimum amount of $5,000,000 and an integral
multiple of $1,000,000 of any Borrowings be, (i) in the case of Base Rate Loans, converted into Eurodollar Loans, or (ii) in the case of
Eurodollar Loans, be converted into a Base Rate Loan or continued as a Eurodollar Loan of such Type (in the absence of delivery of a
Continuation/Conversion Notice with respect to any Eurodollar Loan at least three (3) Business Days before the last day of the then
current Interest Period with respect thereto, such Eurodollar Loan shall, on such last day, automatically convert to a Base Rate Loan);
provided, however, that (i) each such conversion or continuation shall be pro rated among the applicable outstanding Loans of all
Lenders, and (ii) no portion of the outstanding principal amount of any Loans may be continued as, or be converted into, Eurodollar
Loans when any Default has occurred and is continuing.
Funding. Each Lender may, if it so elects, fulfill its obligation to make, continue or convert Eurodollar Loans
SECTION 2.7
hereunder by causing one of its foreign branches or Affiliates (or an international banking facility created by such Lender) to make or
maintain such Eurodollar Loan; provided, however, that such Eurodollar Loan shall nonetheless be deemed to have been made and to
be held by such Lender, and the obligation of the Borrower to repay such Eurodollar Loan shall nevertheless be to such Lender for the
account of such foreign branch, Affiliate or international banking facility. In addition, the Borrower hereby consents and agrees that,
for purposes of any determination to be made for purposes of Sections 4.1, 4.2, 4.3 or 4.4, it shall be conclusively assumed that each
Lender elected to fund all Eurodollar Loans by purchasing, as the case may be, Dollar deposits in its Eurodollar Office’s interbank
eurodollar market.
SECTION 2.8
Repayment of Loans; Evidence of Debt.
(a)
The Borrower hereby unconditionally promises to pay, unless otherwise provided in this Agreement, (i) to the Agent for the
account of each Lender the then unpaid principal amount of each Revolving Loan on the Revolving Commitment Termination Date,
and (ii) to the Agent for the account of each Lender the then unpaid principal amount of each Term Loan on the Maturity Date.
(b)
Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of the
Borrower to such Lender resulting from each Loan made by such Lender, including the amounts of principal and interest payable and
paid to such Lender from time to time hereunder.
17
The Agent shall maintain accounts in which it shall record (i) the amount of each Loan made hereunder and the Interest
(c)
Period applicable thereto, (ii) the amount of any principal or interest due and payable or to become due and payable from the
Borrower to each Lender hereunder and (iii) the amount of any sum received by the Agent hereunder for the account of the Lenders
and each Lender’s share thereof.
The entries made in the accounts maintained pursuant to paragraph (b) or (c) of this Section shall be prima facie evidence of
(d)
the existence and amounts of the obligations recorded therein; provided that the failure of any Lender or the Agent to maintain such
accounts or any error therein shall not in any manner affect the obligation of the Borrower to repay the Loans in accordance with the
terms of this Agreement.
(e)
Any Lender may request that Loans made by it be evidenced by a promissory note, in substantially the form attached as
Exhibit 2.8 hereto. In such event, the Borrower shall prepare, execute and deliver to such Lender a promissory note payable to the
order of such Lender (or, if requested by such Lender, to such Lender and its registered assigns) and in a form approved by the Agent.
Thereafter, the Loans evidenced by such promissory note and interest thereon shall at all times (including after assignment pursuant to
Section 10.10.1) be represented by one or more promissory notes in such form payable to the order of the payee named therein (or, if
such promissory note is a registered note, to such payee and its registered assigns).
ARTICLE III
REPAYMENTS, PREPAYMENTS, INTEREST AND FEES
SECTION 3.1
Loan upon the Revolving Commitment Termination Date unless any such Loans are continued as Term Loans as provided in Section
2.1.2, and (ii) the unpaid principal amount of each Term Loan on the Maturity Date. Prior thereto, the Borrower
Repayments and Prepayments. The Borrower shall repay in full (i) the unpaid principal amount of each Revolving
(a)
may, from time to time on any Business Day, make a voluntary prepayment, in whole or in part, of the outstanding principal
amount of any Loans; provided, however, that (i) any such prepayment shall be applied to the Lenders among Loans having the same
Type and, if applicable, having the same Interest Period; (ii) all such voluntary prepayments shall require at least three Business Days’
prior written notice to the Agent; and (iii) all such voluntary partial prepayments shall be in an minimum amount of $10,000,000 and
an integral multiple of $1,000,000; and
(b)
pursuant to Section 8.3, only a portion of all Loans is so accelerated.
shall, immediately upon any acceleration of the Maturity Date pursuant to Section 8.2 or Section 8.3, repay all Loans unless,
Each prepayment of Loans shall be applied, to the extent of such prepayment, in the inverse order of maturity. Each prepayment of
any Loans made pursuant to this Section shall be without premium or penalty, except as may be required by Section 4.4. No voluntary
prepayment of principal of any Loans shall cause a reduction in the Commitment Amount (except with respect to the repayment or
prepayment of a Term Loan).
18
SECTION 3.2
accordance with this Section 3.2.
Interest Provisions. Interest on the outstanding principal amount of Loans shall accrue and be payable in
Rates. Pursuant to an appropriately delivered Borrowing Request or Continuation/Conversion Notice, the
SECTION 3.2.1
Borrower may elect that Loans comprising a Borrowing accrue interest at a rate per annum: (a) on that portion maintained from time
to time as a Base Rate Loan, equal to the Base Rate from time to time in effect; and (b) on that portion maintained as a Eurodollar
Loan, during each Interest Period applicable thereto, equal to the sum of the Eurodollar Rate for such Interest Period plus the
Applicable Margin. All Eurodollar Borrowings shall bear interest from and including the first day of the applicable Interest Period to
(but not including) the last day of such Interest Period at the interest rate determined as applicable to such Eurodollar Borrowing.
Post−Maturity Rates. After the date any principal amount of any Loan is due and payable (whether on the
SECTION 3.2.2
Maturity Date, upon acceleration or otherwise), or after any other monetary Obligation of the Borrower shall have become due and
payable, the Borrower shall pay, but only to the extent permitted by law, interest (after as well as before judgment) on such amounts at
a rate per annum equal to the Base Rate plus the Default Margin.
Payment Dates. Interest accrued on each Borrowing shall be payable, without duplication on the following dates
SECTION 3.2.3
(each a “Payment Date”): (a) on the Maturity Date; (b) on the date of any payment or prepayment, in whole or in part, of principal
outstanding on such Loan on the amount of such principal prepaid or repaid; (c) with respect to Base Rate Loans, on each Quarterly
Payment Date occurring after the Effective Date; (d) with respect to Eurodollar Borrowings, on the last day of each applicable Interest
Period (and, if such Interest Period shall exceed three months, every three months from the first day of such Interest Period); (e) with
respect to any portion of Base Rate Loans converted into Eurodollar Loans on a day when interest would not otherwise have been
payable pursuant to clause (c), on the date of such conversion; and (f) on that portion of any Borrowings the applicable Maturity Date
of which is accelerated pursuant to Section 8.2 or Section 8.3, immediately upon such acceleration.
SECTION 3.3
Fees. The Borrower agrees to pay the fees set forth in this Section 3.3. All such fees shall be non−refundable.
SECTION 3.3.1
equal to the product of the Applicable Facility Fee Rate times such Lender’s Percentage of Revolving Commitments times the
Commitment Amount. Accrued facility fees shall be payable in arrears on each Quarterly Payment Date and on the Maturity Date.
Facility Fee. The Borrower agrees to pay to the Agent for the account of each Lender a facility fee in an amount
SECTION 3.3.2
respectively, all fees (including any fees pursuant to Section 2.2.8) pursuant to that certain fee letter agreement, dated October 1, 2003,
between the Borrower and the Agent, as amended from time to time (the “Fee Letter”).
Fees. The Borrower agrees to pay to the Agent for its own account and for the account of each Lender,
SECTION 3.3.3
Payment Office. The Borrower shall make all payments to the Agent at the Payment Office.
19
ARTICLE IV
CERTAIN EURODOLLAR AND OTHER PROVISIONS
Eurodollar Lending Unlawful. If any Lender shall determine (which determination shall, upon notice thereof to
SECTION 4.1
the Borrower and the Lenders, be conclusive and binding on the Borrower) that the introduction of or any change in or in the
interpretation of any law makes it unlawful, or any central bank or other governmental authority asserts that it is unlawful, for such
Lender to make, continue or maintain any Borrowing as, or to convert any Borrowing into, a Eurodollar Borrowing, the obligations of
such Lender to make, continue, maintain or convert any such Borrowings shall, upon such determination, forthwith be suspended until
such Lender shall notify the Agent that the circumstances causing such suspension no longer exist, and all Eurodollar Borrowings
shall automatically convert into Base Rate Loans at the end of the then current Interest Periods with respect thereto or sooner, if
required by such law or assertion; provided, however, that the obligation of such Lender to make, continue, maintain or convert any
such Eurodollar Borrowings shall remain unaffected if such Lender can designate a different Eurodollar Office for the making,
continuance, maintenance or conversion of Eurodollar Borrowings and such designation will not, in the sole discretion of such Lender,
be otherwise disadvantageous to such Lender.
Deposits Unavailable or Eurodollar Interest Rate Unascertainable. If the Agent shall have determined that, by
SECTION 4.2
reason of circumstances affecting the Agent’s relevant market, adequate means do not exist for ascertaining the interest rate applicable
hereunder to Eurodollar Borrowings, then, upon notice from the Agent to the Borrower and the Lenders, the obligations of all Lenders
under Section 2.5.2 and Section 2.6 to make or continue any Borrowings as, or to convert any Borrowings into, Eurodollar
Borrowings shall forthwith be suspended until the Agent shall notify the Borrower and the Lenders that the circumstances causing
such suspension no longer exist.
Increased Eurodollar Borrowing Costs, etc. The Borrower agrees to reimburse each Lender for any increase in the
SECTION 4.3
cost to such Lender of, or any reduction in the amount of any sum receivable by such Lender in respect of, making, continuing or
maintaining (or of its obligation to make, continue or maintain) any Borrowings as, or of converting (or of its obligation to convert)
any Borrowings into, Eurodollar Borrowings. Such Lender shall promptly notify the Agent and the Borrower in writing of the
occurrence of any such event, such notice to state, in reasonable detail, the reasons therefor and the additional amount required fully to
compensate such Lender for such increased cost or reduced amount; provided, however, that such Lender shall designate a different
Eurodollar Office if such designation will avoid the need for, or reduce the amount of, such compensation and will not, in the sole
discretion of such Lender, be otherwise disadvantageous to such Lender. Such additional amounts shall be payable by the Borrower
directly to such Lender within fifteen days of its receipt of such notice, and such notice shall be rebuttable presumptive evidence of the
amount payable by the Borrower.
SECTION 4.4
Funding Losses. In the event any Lender shall incur any loss or expense (including any loss or expense incurred
by reason of the liquidation or reemployment of deposits or other funds acquired by such Lender to make, continue or maintain any
portion of the principal amount of any Borrowing as, or to convert any portion of the principal amount of any Borrowing into, a
Eurodollar Borrowing) as a result of (a) any conversion or repayment or
20
prepayment of the principal amount of any Eurodollar Borrowings on a date other than the scheduled last day of the Interest Period
applicable thereto, whether pursuant to Section 3.1 or otherwise, (b) any Borrowings not being made as Eurodollar Borrowings in
accordance with the Borrowing Request, as the case may be, therefor, (c) any Borrowings not being continued as, or converted into,
Eurodollar Borrowings in accordance with the Continuation/Conversion Notice, or (d) the assignment of any Eurodollar Borrowing
other than on the last day of the Interest Period applicable thereto as a result of a request by the Borrower pursuant to Section 4.10,
therefor, then, upon the written notice of such Lender to the Borrower (with a copy to the Agent), the Borrower shall, within fifteen
days of its receipt thereof, pay directly to such Lender such amount as will (in the reasonable determination of such Lender) reimburse
such Lender for such loss or expense. Such written notice (which shall include calculations in reasonable detail) shall be rebuttable
presumptive evidence of the amount payable by the Borrower.
Increased Capital Costs. If any change in, or the introduction, adoption, effectiveness, interpretation,
SECTION 4.5
reinterpretation or phase−in of, any law or regulation, directive, guideline, decision or request (whether or not having the force of law)
of any court, central bank, regulator or other governmental authority affects or would affect the amount of capital required or expected
to be maintained by any Lender or any Person controlling such Lender, and such Lender determines (in its sole discretion) that the rate
of return on its or such controlling Person’s capital as a consequence of its Commitments or the Borrowings made by such Lender is
reduced to a level below that which such Lender or such controlling Person could have achieved but for the occurrence of any such
circumstance, then, in any such case upon notice from time to time by such Lender to the Borrower, the Borrower shall pay directly to
such Lender, within fifteen days, additional amounts sufficient to compensate such Lender or such controlling Person for such
reduction in rate of return; provided, however, that such Lender shall designate a different Domestic or Eurodollar Office if such
designation will avoid the need for, or reduce the amount of, such compensation and will not, in the sole discretion of such Lender, be
otherwise disadvantageous to such Lender. A statement of such Lender as to any such additional amount or amounts (including
calculations thereof in reasonable detail) shall be rebuttable presumptive evidence of the amount payable by the Borrower. In
determining such amount, such Lender may use any reasonable method of averaging and attribution that it (in its sole discretion) shall
deem applicable.
Taxes. All payments by the Borrower of principal of, and interest on, the Borrowings and all other amounts
SECTION 4.6
payable hereunder shall be made free and clear of and without deduction for any present or future income, excise, stamp or franchise
taxes and other taxes, fees, duties, withholdings or other charges of any nature whatsoever imposed by any taxing authority, but
excluding franchise taxes and taxes imposed on or measured by any Lender’s net income or receipts (such non−excluded items being
called “Taxes”). In the event that any withholding or deduction from any payment to be made by the Borrower hereunder is required
in respect of any Taxes pursuant to any applicable law, rule or regulation, then the Borrower will, within fifteen days (a) pay directly
to the relevant authority the full amount required to be so withheld or deducted; (b) promptly forward to the Agent an official receipt
or other documentation satisfactory to the Agent evidencing such payment to such authority; and (c) pay to the Agent for the account
of the Lenders such additional amount or amounts as is necessary to ensure that the net amount actually received by each Lender will
equal the full amount such Lender would have received had no such withholding or deduction been required.
21
If any Taxes are directly asserted against the Agent or any Lender with respect to any payment received by the Agent or such Lender
hereunder, the Agent or such Lender may pay such Taxes and the Borrower will promptly pay such additional amounts (including any
penalties, interest or expenses) as is necessary in order that the net amount received by such person after the payment of such Taxes
(including any Taxes on such additional amount) shall equal the amount such person would have received had not such Taxes been
asserted; provided that the Borrower will not be obligated to pay such additional amounts to the Agent or such Lender to the extent
that such additional amounts shall have been incurred as a consequence of the Agent’s or such Lender’s gross negligence or willful
misconduct, as the case may be.
If the Borrower fails to pay any Taxes when due to the appropriate taxing authority or fails to remit to the Agent, for the account of the
respective Lenders, the required receipts or other required documentary evidence, the Borrower shall indemnify the Lenders for any
incremental Taxes, interest or penalties that may become payable by any Lender as a result of any such failure. For purposes of this
Section, a distribution hereunder by the Agent or any Lender to or for the account of any Lender shall be deemed a payment by the
Borrower.
Each Lender that is organized under the laws of a jurisdiction other than the United States shall, prior to the due date of any payments
of the Loans under this Agreement, execute and deliver to the Borrower and the Agent, on or about the first scheduled Payment Date
in each Fiscal Year, one or more (as the Borrower or the Agent may reasonably request) United States Internal Revenue Service
Form W−8 BEN or Form W−8 ECI or such other forms or documents (or successor forms or documents), appropriately completed, as
may be applicable to establish the extent, if any, to which a payment to such Lender is exempt from withholding or deduction of
Taxes, and shall (but only so long as such Lender remains lawfully able to do so) deliver to the Borrower and the Agent additional
copies of such forms on or before the date that such forms expire or become obsolete or after the occurrence of an event requiring a
change in the most recent form so delivered by it and such amendments thereto as may be reasonably requested by the Borrower or the
Agent, in each case certifying that such Lender is entitled to benefits under an income tax treaty to which the United States is a party
which reduces the rate of withholding tax on payments of interest or fees or certifying that the income receivable pursuant to this
Agreement is effectively connected with the conduct of a trade or business in the United States. If the form provided by a Lender at
the time such Lender first becomes a party to this Agreement indicates a United States withholding tax rate in excess of zero,
withholding tax at such rate shall be considered excluded from the definition of “Taxes”. For any period with respect to which a
Lender has failed to provide the Borrower and the Agent with the forms required pursuant to this paragraph, if any (other than if such
failure is due to a change in treaty, law or regulation occurring subsequent to the date on which a form originally was required to be
provided), such Lender shall not be entitled to indemnification under this Section with respect to Taxes imposed by the United States
which Taxes would not have been imposed but for such failure to provide such form; provided, however, that should a Lender, which
is otherwise exempt from or subject to a reduced rate of withholding tax, become subject to Taxes because of its failure to deliver a
form required hereunder, the Borrower shall take such steps as the Lender shall reasonably request to assist the Lender to recover such
Taxes.
If the Borrower is required to pay additional amounts to or for the account of any Lender pursuant to this Section, then such Lender
will change the jurisdiction of its applicable
22
Eurodollar or Domestic Office so as to eliminate or reduce any such additional payment which may thereafter accrue if such change,
in the sole discretion of such Lender, is not otherwise disadvantageous to such Lender. No Lender shall be entitled to receive any
greater payment under this Section as a result of the designation by such Lender of a different applicable Eurodollar or Domestic
Office after the date hereof, unless such designation is made with the Borrower’s prior written consent or by reason of the provisions
of Sections 4.1, 4.3 or 4.5 requiring such Lender to designate a different applicable Eurodollar or Domestic Office under certain
circumstances or at a time when the circumstances giving rise to such greater payment did not exist.
Special Fees in Respect of Reserve Requirements. With respect to Eurodollar Borrowings, the Borrower agrees to
SECTION 4.7
pay to each Lender on appropriate Payment Dates, as additional interest, such amounts as will compensate such Lender for any cost to
such Lender, from time to time, of any reserve, special deposit, special assessment or similar capital requirements against assets of,
deposits with or for the account of, or credit extended by, such Lender which are imposed on, or deemed applicable by, such Lender,
from time to time, under or pursuant to (i) any Law, treaty, regulation or directive now or hereafter in effect (including, without
limitation, Regulation D of the Board of Governors of the Federal Reserve System but excluding any reserve requirement included in
the definition of Eurodollar Rate in Section 1.1), (ii) any interpretation or application thereof by any governmental authority, agency
or instrumentality charged with the administration thereof or by any court, central bank or other fiscal, monetary or other authority
having jurisdiction over the Eurodollar Borrowings or the office of such Lender where its Eurodollar Borrowings are lodged, or
(iii) any requirement imposed or requested by any court, governmental authority, agency or instrumentality or central bank, fiscal,
monetary or other authority, whether or not having the force of law. A written notice as to the amount of any such cost or any change
therein (including calculations, in reasonable detail, showing how such Lender computed such cost or change) shall be promptly
furnished by such Lender to the Borrower and shall be rebuttable presumptive evidence of such cost or change. The Borrower will not
be responsible for paying any amounts pursuant to this Section accruing prior to 180 days prior to the receipt by the Borrower of the
written notice referred to in the preceding sentence. Within fifteen (15) days after such certificate is furnished to the Borrower, the
Borrower will pay directly to such Lender such additional amount or amounts as will compensate such Lender for such cost or change.
SECTION 4.8
Payments, Computations, etc. Unless otherwise expressly provided, all payments by the Borrower pursuant to this
Agreement or any other Loan Document shall be made by the Borrower to the Agent for the pro rata account of the Lenders entitled to
receive such payment. All such payments required to be made to the Agent shall be made, without setoff, deduction or counterclaim,
not later than 11:00 a.m., Central time, on the date due, in same day or immediately available funds, to such account as the Agent shall
specify from time to time by notice to the Borrower. Funds received after that time shall be deemed to have been received by the
Agent on the next succeeding Business Day. The Agent shall promptly remit in same day funds to each Lender its share, if any, of
such payments received by the Agent for the account of such Lender. All interest and fees shall be computed on the basis of the actual
number of days (including the first day but excluding the last day) occurring during the period for which such interest or fee is payable
over a year comprised of 360 days (or, in the case of interest on a Base Rate Loan, 365 days or, if appropriate, 366 days). Whenever
any payment to
23
be made shall otherwise be due on a day which is not a Business Day, such payment shall (except as otherwise required by clause (c)
of the definition of the term “Interest Period” with respect to Eurodollar Loans) be made on the next succeeding Business Day and
such extension of time shall be included in computing interest and fees, if any, in connection with such payment.
SECTION 4.9
Sharing of Payments. If any Lender shall obtain any payment or other recovery (whether voluntary, involuntary,
by application of setoff or otherwise) on account of any Loan (other than pursuant to the terms of Sections 4.3, 4.4 and 4.5) in excess
of its pro rata share of payments then or therewith obtained by all Lenders, such Lender shall purchase from the other Lenders such
participations in Loans made by them as shall be necessary to cause such purchasing Lender to share the excess payment or other
recovery ratably with each of them; provided, however, that if all or any portion of the excess payment or other recovery is thereafter
recovered from such purchasing Lender, the purchase shall be rescinded and each Lender which has sold a participation to the
purchasing Lender shall repay to the purchasing Lender the purchase price to the ratable extent of such recovery together with an
amount equal to such selling Lender’s ratable share (according to the proportion of (a) the amount of such selling Lender’s required
repayment to the purchasing Lender to (b) the total amount so recovered from the purchasing Lender) of any interest or other amount
paid or payable by the purchasing Lender in respect of the total amount so recovered. The Borrower agrees that any Lender so
purchasing a participation from another Lender pursuant to this Section may, to the fullest extent permitted by law, exercise all its
rights of payment with respect to such participation as fully as if such Lender were the direct creditor of the Borrower in the amount of
such participation. If under any applicable bankruptcy, insolvency or other similar law, any Lender receives a secured claim in lieu of
a set off to which this Section applies, such Lender shall, to the extent practicable, exercise its rights in respect of such secured claim
in a manner consistent with the rights of the Lenders entitled under this Section to share in the benefits of any recovery on such
secured claim.
Replacement of Lender on Account of Increased Costs, Eurodollar Lending Unlawful, Reserve Requirements,
SECTION 4.10
Taxes, Certain Dissents, etc. If any Lender shall claim the inability to make or maintain Eurodollar Borrowings pursuant to Section
4.1 above, if any Lender is owed increased costs under Section 4.5 above, if any payment to any Lender by the Borrower is subject to
any withholding tax pursuant to Section 4.6 above, or if any Lender is owed any cost or expense pursuant to Section 4.7 above, the
Borrower shall have the right, if no Event of Default or Default then exists, to replace such Lender with another bank or financial
institution provided that (i) if it is not a Lender or an Affiliate thereof, such bank or financial institution shall be reasonably acceptable
to the Agent and (ii) such bank or financial institution shall unconditionally purchase, in accordance with Section 10.10 hereof, all of
such Lender’s rights and obligations under this Agreement and the other Loan Documents and the appropriate pro rata share of such
Lender’s Loans and Commitments, without recourse or expense to, or warranty by, such Lender being replaced for a purchase price
equal to the aggregate outstanding principal amount of the Loans payable to such Lender, plus any accrued but unpaid interest on such
Loans, plus accrued but unpaid fees in respect of such Lender’s Borrowings and Percentage of the Commitments hereunder to the date
of such purchase on a date therein specified. The Borrower shall be obligated to pay, simultaneously with such purchase and sale, the
increased costs, amounts, expenses and taxes under Sections 4.1, 4.5, 4.6, and 4.7 above, any amounts payable under Section 4.4 and
all other costs, fees and expenses payable to such Lender
24
hereunder and under the Loan Documents, to the date of such purchase as well as all other Obligations due and payable to or for the
benefit of such Lender; provided, that if such bank or financial institution fails to purchase such rights and obligations, the Borrower
shall continue to be obligated to pay the increased costs, amounts, expenses and taxes under Sections 4.1, 4.5, 4.6, and 4.7 above to
such Lender.
SECTION 4.11 Maximum Interest. It is the intention of the parties hereto to conform strictly to applicable usury laws and,
anything herein to the contrary notwithstanding, the obligations of the Borrower to the Agent and each Lender under this Agreement
shall be subject to the limitation that payments of interest shall not be required to the extent that receipt thereof would be contrary to
provisions of law applicable to the Agent or such Lender limiting rates of interest which may be charged or collected by the Agent or
such Lender. Accordingly, if the transactions contemplated hereby would be usurious under applicable law (including the Federal and
state laws of the United States of America, or of any other jurisdiction whose laws may be mandatorily applicable) with respect to the
Agent or a Lender then, in that event, notwithstanding anything to the contrary in this Agreement, it is agreed as follows: (a) the
provisions of this Section shall govern and control; (b) the aggregate of all consideration which constitutes interest under applicable
law that is contracted for, charged or received under this Agreement, or under any of the other aforesaid agreements or otherwise in
connection with this Agreement by the Agent or such Lender shall under no circumstances exceed the maximum amount of interest
allowed by applicable law (such maximum lawful interest rate, if any, with respect to such Lender herein called the “Highest Lawful
Rate”), and any excess shall be credited to the Borrower by the Agent or such Lender (or, if such consideration shall have been paid in
full, such excess refunded to the Borrower); (c) all sums paid, or agreed to be paid, to the Agent or such Lender for the use,
forbearance and detention of the Indebtedness of the Borrower to the Agent or such Lender hereunder shall, to the extent permitted by
applicable law, be amortized, prorated, allocated and spread throughout the full term of such Indebtedness until payment in full so that
the actual rate of interest is uniform throughout the full term thereof; and (d) if at any time the interest provided pursuant to
Section 4.1 together with any other fees payable pursuant to this Agreement and the other Loan Documents and deemed interest under
applicable law, exceeds that amount which would have accrued at the Highest Lawful Rate, the amount of interest and any such fees
to accrue to the Agent or such Lender pursuant to this Agreement shall be limited, notwithstanding anything to the contrary in this
Agreement to that amount which would have accrued at the Highest Lawful Rate, but any subsequent reductions, as applicable, shall
not reduce the interest to accrue to the Agent or such Lender pursuant to this Agreement below the Highest Lawful Rate until the total
amount of interest accrued pursuant to this Agreement and such fees deemed to be interest equals the amount of interest which would
have accrued to the Agent or such Lender if a varying rate per annum equal to the interest provided pursuant to Section 3.2 had at all
times been in effect, plus the amount of fees which would have been received but for the effect of this Section. For purposes of
Section 303.201 of the Texas Finance Code, as amended, to the extent, if any, applicable to the Agent or a Lender, the Borrower
agrees that the Highest Lawful Rate shall be the “indicated (weekly) rate ceiling” as defined in said Section, provided that the Agent
or such Lender may also rely, to the extent permitted by applicable laws, on alternative maximum rates of interest under other laws
applicable to the Agent or such Lender if greater. Chapter 346 of the Texas Finance Code (which regulates certain revolving credit
loan accounts and revolving tri−party accounts
25
(formerly Tex. Rev. Civ. Stat. Ann. Art. 5069, Ch. 15)) shall not apply to this Agreement or the other Loan Documents.
ARTICLE V
CONDITIONS
SECTION 5.1
satisfaction, or waiver in writing by the Agent (with the consent of Required Lenders) of each of the conditions precedent set forth in
this Section 5.1.
Effective Date. The obligations of the Lenders to fund the initial Borrowing shall be subject to the prior
SECTION 5.1.1
Resolutions, etc. The Agent shall have received from the Borrower a certificate, dated the Effective Date, of its
Secretary or Assistant Secretary as to (a) resolutions of its Board of Directors then in full force and effect authorizing the execution,
delivery and performance of this Agreement and each other Loan Document to be executed by it; and (b) the incumbency and
signatures of its Authorized Officers, upon which certificate each Lender may conclusively rely until it shall have received a further
certificate of the Secretary of the Borrower canceling or amending such prior certificate.
SECTION 5.1.2
[Intentionally omitted].
SECTION 5.1.3
the Agent and all Lenders, from Thompson & Knight L.L.P., counsel to the Borrower, substantially in the form of Exhibit 5.1.3
hereto.
Opinion of Counsel. The Agent shall have received a favorable opinion, dated the Effective Date and addressed to
SECTION 5.1.4
Borrower. The Agent shall also have received for its own account, or for the account of the Arranger and each Lender, as the case
may be, all fees, costs and expenses due and payable pursuant to Sections 3.3 and 10.3, if then invoiced.
Fee Letters, Closing Fees, Expenses, etc. The Agent shall have received the Fee Letter duly executed by the
SECTION 5.1.5 Material Adverse Change. There shall have been no material adverse change in the consolidated business,
condition (financial or otherwise), operations, performance or properties of any of the Borrower and its consolidated Subsidiaries
taken as a whole since June 30, 2003, except as disclosed in Item 5.1.5 (“Material Adverse Change”) of the Disclosure Schedule.
SECTION 5.1.6
Existing Credit Facility and any obligations of the Borrower in connection therewith on the Effective Date.
Existing Credit Facility. The Agent shall have received satisfactory proof of the Borrower’s termination of the
SECTION 5.1.7
Other Documents. Such other documents as the Agent or any Lender may have reasonably requested.
SECTION 5.2
subject to the satisfaction of each of the conditions precedent set forth in this Section.
All Borrowings. The obligation of each Lender to fund any Borrowing (including the initial Borrowing) shall be
SECTION 5.2.1
Default of the nature referred to in Section 8.1.5
Compliance with Warranties, No Default, etc. Both before and after giving effect to any Borrowing (but, if any
26
shall have occurred with respect to any other Indebtedness, without giving effect to the application, directly or indirectly, of the
proceeds thereof) the following statements shall be true and correct (a) the representations and warranties set forth in Article VI shall
be true and correct with the same effect as if then made (unless stated to relate solely to an earlier date, in which case such
representations and warranties shall be true and correct as of such earlier date); and (b) no Default or Event of Default shall have then
occurred and be continuing.
Borrowing Request. The Agent shall have received a Borrowing Request for such Borrowing. Each of the
SECTION 5.2.2
delivery of a Borrowing Request and the acceptance by the Borrower of the proceeds of such Borrowing shall constitute a
representation and warranty by the Borrower that on the date of such Borrowing (both immediately before and after giving effect to
such Borrowing and the application of the proceeds thereof) the statements made in Section 5.2.1 are true and correct.
SECTION 5.2.3
any of its Subsidiaries shall be satisfactory in form and substance to the Agent and its counsel; the Agent and its counsel shall have
received all information, approvals, opinions, documents or instruments as the Agent or its counsel may reasonably request.
Satisfactory Legal Form. All documents executed or submitted pursuant hereto by or on behalf of the Borrower or
ARTICLE VI
REPRESENTATIONS AND WARRANTIES
In order to induce the Lenders and the Agent to enter into this Agreement and to make Loans hereunder, the Borrower represents and
warrants unto the Agent and each Lender as set forth in this Article VI.
Organization, etc. The Borrower and each of its Restricted Subsidiaries is a corporation, partnership, limited
SECTION 6.1
partnership or limited liability company validly organized and existing and in good standing under the laws of the State of its
incorporation, is duly qualified to do business and is in good standing as a foreign entity in each jurisdiction where the nature of its
business requires such qualification, and has full power and authority and holds all requisite governmental licenses, permits and other
approvals to enter into and perform its Obligations under this Agreement and each other Loan Document to which it is a party and to
conduct its business substantially as currently conducted by it (except where the failure to be so qualified to do business or be in good
standing or to hold any such licenses, permits and other approvals will not have a Material Adverse Effect).
Due Authorization, Non−Contravention, etc. The execution, delivery and performance by the Borrower of this
SECTION 6.2
Agreement and each other Loan Document executed or to be executed by it, and the Borrower’s participation in any transaction
contemplated herein are within the Borrower’s powers, have been duly authorized by all necessary corporate action, and do not
(a) contravene the Borrower’s Organic Documents; (b) contravene any contractual restriction, law or governmental regulation or court
decree or order binding on or affecting the Borrower; or (c) result in, or require the creation or imposition of, any Lien on any of the
Borrower’s properties.
27
SECTION 6.3
Government Approval, Regulation, etc. No authorization or approval or other action by, and no notice to or filing
with, any governmental authority or regulatory body or other Person is required for the due execution, delivery or performance by the
Borrower of this Agreement or any other Loan Document to which it is a party, or for the Borrower’s participation in any transaction
contemplated herein, except as have been obtained. Neither the Borrower nor any of its Subsidiaries is an “investment company”
within the meaning of the Investment Company Act of 1940, as amended, or a “holding company”, or a “subsidiary company” of a
“holding company”, or an “affiliate” of a “holding company” or of a “subsidiary company” of a “holding company”, within the
meaning of the Public Utility Holding Company Act of 1935, as amended.
Validity, etc. This Agreement constitutes, and each other Loan Document executed by the Borrower will, on the
SECTION 6.4
due execution and delivery thereof, constitute, the legal, valid and binding obligations of the Borrower enforceable in accordance with
their respective terms except as (i) enforceability thereof may be limited by bankruptcy, insolvency or similar laws affecting creditor’s
rights generally and (ii) rights of acceleration and the availability of equitable remedies may be limited by equitable principles of
general applicability.
Financial Information. The balance sheets of the Borrower and each of its consolidated Subsidiaries as at June 30,
SECTION 6.5
2003 and the related statements of earnings and cash flow, copies of which have been furnished to the Agent and each Lender, have
been prepared in accordance with GAAP consistently applied, and present fairly the consolidated financial condition of the
corporations covered thereby as at the dates thereof and the results of their operations for the periods then ended except as disclosed in
Item 6.5 (“Financial Information”) of the Disclosure Schedule.
No Material Adverse Change. As of the Effective Date, since the date of the financial statements described in
SECTION 6.6
Section 6.5, there has been no material adverse change in the financial condition, operations, assets, business or properties of the
Borrower and its Restricted Subsidiaries (on a consolidated basis), except as disclosed in Item 5.1.5 (“Material Adverse Change”) of
the Disclosure Schedule.
Litigation, Labor Controversies, etc. As of the Effective Date, there is no pending or, to the knowledge of the
SECTION 6.7
Borrower, threatened litigation, action, proceeding, or labor controversy affecting the Borrower or any of its Restricted Subsidiaries,
or any of their respective properties, businesses, assets or revenues, which could reasonably be expected to have a Material Adverse
Effect or which purports to affect the legality, validity or enforceability of, and the rights and remedies of the Agent and the Lenders
under, this Agreement or any other Loan Document, except as disclosed in Item 6.7 (“Litigation”) of the Disclosure Schedule.
SECTION 6.8
Subsidiaries. Schedule 6.8 sets forth the name, the identity or corporate structure and the ownership interest of
each direct or indirect Subsidiary as of the Effective Date. Schedule 6.8 also sets forth the name of each Restricted Subsidiary and
Unrestricted Subsidiary as of the Effective Date. As of the Effective Date, the Borrower does not have any Subsidiaries other than the
Subsidiaries identified in Schedule 6.8.
28
Taxes. The Borrower, each of its Restricted Subsidiaries and each of its Unrestricted Subsidiaries which is a
SECTION 6.9
member of the Borrower’s consolidated U.S. federal income tax group has filed all federal tax returns and reports and all material state
tax returns and reports required by law to have been filed by it and has paid all taxes and governmental charges thereby shown to be
owing, except any such taxes or charges which are being diligently contested in good faith by appropriate proceedings and for which
adequate reserves in accordance with GAAP shall have been set aside on its books except such returns and taxes for jurisdictions other
than the United States with respect to which the failure to file and pay such taxes would not have a Material Adverse Effect.
Pension and Welfare Plans. During the twelve−consecutive−month period prior to the date of the execution and
SECTION 6.10
delivery of this Agreement and prior to the date of any Borrowing hereunder, no steps have been taken to terminate any Pension Plan,
and no contribution failure has occurred with respect to any Pension Plan sufficient to give rise to a Lien securing an amount in excess
of $1,000,000 under section 302(f) of ERISA. No condition exists or event or transaction has occurred with respect to any Pension
Plan which might result in the incurrence by the Borrower or any member of the Controlled Group of any liability, fine or penalty
which could reasonably be expected to result in a Material Adverse Effect. Except as disclosed in Item 6.10 (“Employee Benefit
Plans”) of the Disclosure Schedule, neither the Borrower nor any member of the Controlled Group has any contingent liability with
respect to any post−retirement benefit under a Welfare Plan, other than liability for continuation coverage described in Part 6 of Title I
of ERISA.
SECTION 6.11
Restricted Subsidiaries related to compliance with applicable Environmental Laws (as in effect on the date on which this
representation is made or deemed made) could not reasonably be expected to have a Material Adverse Effect.
Environmental Warranties and Compliance. The liabilities and costs of the Borrower and its consolidated
SECTION 6.12
purpose of purchasing or carrying Margin Stock, and no proceeds of any Loans will be used for a purpose which violates, or would be
inconsistent with, Regulation U.
Regulation U. None of the Borrower and its Subsidiaries are engaged in the business of extending credit for the
Accuracy of Information. No certificate, statement or other information delivered herewith or hereto by or on
SECTION 6.13
behalf of the Borrower in writing to the Agent or any Lender in connection with the negotiation of this Agreement or in connection
with any transaction contemplated hereby contains any untrue statement of a fact or omits to state any fact known to the Borrower or
its Subsidiaries necessary to make the statements contained herein or therein not misleading as of the date made or deemed made,
except to the extent that any untrue statement or omission could not reasonably be expected to have a Material Adverse Effect.
SECTION 6.14
Borrower and its Subsidiaries. No proceeds of any Borrowing shall be used to make any investment in any Person if the board of
directors or other governing body of such Person has announced its opposition to such investment.
Use of Proceeds. The proceeds of each Borrowing shall be used for the general corporate purposes of the
29
ARTICLE VII
COVENANTS
SECTION 7.1
terminated and all Obligations have been paid and performed in full, the Borrower will perform the obligations set forth in this Section
7.1.
Affirmative Covenants. The Borrower agrees with the Agent and each Lender that, until all Commitments have
SECTION 7.1.1
Lender and the Agent copies of the following financial statements, reports, notices and information:
Financial Information, Reports, Notices, etc. The Borrower will furnish, or will cause to be furnished, to each
as soon as available and in any event within 45 days after the end of each of the first three Fiscal Quarters of each Fiscal
(a)
Year of the Borrower, consolidated balance sheets of the Borrower and its Subsidiaries as of the end of such Fiscal Quarter and
consolidated statements of earnings and cash flow of the Borrower and its Subsidiaries for such Fiscal Quarter and for the period
commencing at the end of the previous Fiscal Year and ending with the end of such Fiscal Quarter, certified by the chief financial
Authorized Officer of the Borrower as having been prepared in accordance with GAAP;
as soon as available and in any event within 90 days after the end of each Fiscal Year of the Borrower, a copy of the annual
(b)
audit report for such Fiscal Year for the Borrower and its Subsidiaries, including therein consolidated balance sheets of the Borrower
and its Subsidiaries as of the end of such Fiscal Year and consolidated statements of earnings and cash flow of the Borrower and its
Subsidiaries for such Fiscal Year, in each case certified (without any Impermissible Qualification) as having been prepared in
accordance with GAAP in a manner acceptable to the Agent and the Required Lenders by independent public accountants of
recognized national standing;
as soon as available and in any at the time of each delivery of financial reports under subsections (a) and (b) of this Section
(c)
7.1.1, a certificate, executed by the chief financial Authorized Officer of the Borrower, showing (in reasonable detail and with
appropriate calculations and computations in all respects satisfactory to the Agent) compliance with the financial covenants set forth in
Section 7.2.3;
promptly, and in any event within three Business Days after an Authorized Officer of the Borrower or any of its Subsidiaries
(d)
becomes aware of the existence of the occurrence of each Default, a statement of the chief executive officer or the chief financial
Authorized Officer of the Borrower setting forth details of such Default and the action which the Borrower has taken and proposes to
take with respect thereto;
promptly, and in any event within three Business Days after an Authorized Officer of the Borrower or any of its Subsidiaries
(e)
becomes aware of (x) the occurrence of any adverse development with respect to any litigation, action, proceeding, or labor
controversy described in Section 6.7 which would have or reasonably be expected to have a Material Adverse Effect, or (y) the
commencement of any material labor controversy, litigation, action, proceeding of the type described in Section 6.7 which would have
or reasonably be expected to have a
30
Material Adverse Effect, notice thereof and copies of all documentation relating thereto requested by the Agent or any Lender;
(f)
Subsidiaries files with the Securities and Exchange Commission or any national securities exchange;
promptly after the sending or filing thereof, copies of all reports and registration statements which the Borrower or any of its
immediately upon becoming aware of the institution of any steps by the Borrower or any other Person to terminate any
(g)
Pension Plan, or the failure to make a required contribution to any Pension Plan if such failure is sufficient to give rise to a Lien under
section 302(f) of ERISA, or the taking of any action with respect to a Pension Plan which could result in the requirement that the
Borrower furnish a bond or other security to the PBGC or such Pension Plan, or the occurrence of any event with respect to any
Pension Plan which could result in the incurrence by the Borrower of any liability, fine or penalty, or any increase in the contingent
liability of the Borrower with respect to any post−retirement Welfare Plan benefit which would have or could reasonably be expected
to have a Material Adverse Effect, notice thereof and copies of all documentation relating thereto; and
(h)
Subsidiaries as any Lender through the Agent may from time to time reasonably request.
such other information respecting the condition or operations, financial or otherwise, of the Borrower or any of its
SECTION 7.1.2 Compliance with Laws, etc. The Borrower will, and will cause each of its Subsidiaries to, comply with all Laws,
such compliance to include, without limitation: (a) the maintenance and preservation of its corporate existence and qualification as a
foreign corporation, (b) the payment, before the same become delinquent, of all taxes, assessments and governmental charges imposed
upon it or upon its property except to the extent being diligently contested in good faith by appropriate proceedings and for which
adequate reserves in accordance with GAAP shall have been set aside on its books and (c) all Environmental Laws; except; in each
case, where the failure to so comply would not have or would not reasonably be expected to have a Material Adverse Effect.
SECTION 7.1.3 Maintenance of Properties. The Borrower will, and will cause each of its Restricted Subsidiaries to, maintain,
preserve, protect and keep its properties in good repair, working order and condition (ordinary wear and tear excepted), and make
necessary and proper repairs, renewals and replacements so that its business carried on in connection therewith may be properly
conducted at all times unless the Borrower determines in good faith that the continued maintenance of any of its properties is no
longer economically desirable or unless failure to so preserve, maintain, protect or keep its properties would not reasonably be
expected to have a Material Adverse Effect.
SECTION 7.1.4 Insurance. The Borrower will, and will cause each of its Restricted Subsidiaries to, maintain or cause to be
maintained with responsible insurance companies insurance with respect to its properties and business against such casualties and
contingencies and of such types and in such amounts as is customary in the case of similar businesses in similar locations.
31
SECTION 7.1.5 Books and Records. The Borrower will, and will cause each of its Subsidiaries to, keep books and records which
accurately reflect, in accordance with GAAP, all of its business affairs and transactions and permit the Agent or its representatives, at
reasonable times and intervals and upon reasonable prior notice to the Borrower, to visit all of its offices, to discuss its financial
matters with its officers and employees and to examine any of its books or other corporate records; provided, however, that prior
notice to the Borrower shall not be required if an Event of Default has occurred or is continuing.
SECTION 7.1.6 Conduct of Business. The Borrower will, and will cause each Restricted Subsidiary to, cause all material
properties and businesses to be regularly conducted, operated, maintained and developed in a good and workmanlike manner, as
would a prudent operator and in accordance with all applicable federal, state and local laws, rules and regulations, except for any
failure to so operate, maintain and develop that could not reasonably be expected to have a Material Adverse Effect.
SECTION 7.1.7 Subsidiaries; Unrestricted Subsidiaries. The Borrower shall:
(a)
Subsidiary is an Unrestricted Subsidiary or a Restricted Subsidiary.
if any additional Subsidiary is formed or acquired after the Effective Date, notify the Agent thereof and whether such
cause the management, business and affairs of the Borrower and its Restricted Subsidiaries to be conducted in such a manner
(b)
(including, without limitation, by keeping separate books of account, furnishing separate financial statements of Unrestricted
Subsidiaries to creditors and potential creditors thereof and by not permitting Properties of the Borrower and its respective
Subsidiaries to be commingled) so that each Unrestricted Subsidiary that is a corporation will be treated as a corporate entity separate
and distinct from the Borrower and the Restricted Subsidiaries;
(c)
Liabilities in respect of any Indebtedness of any of the Unrestricted Subsidiaries; and
except as permitted by Section 7.2.5, will not, and will not permit any of the Restricted Subsidiaries to incur any Guaranteed
(d)
Restricted Subsidiary.
will not permit any Unrestricted Subsidiary to hold any equity or other ownership interest in, or any Indebtedness of, any
SECTION 7.1.8 Designation and Conversion of Restricted and Unrestricted Subsidiaries.
Unless designated as an Unrestricted Subsidiary on Schedule 6.8 as of the date of this Agreement or thereafter in writing to
(a)
the Agent, any Person that becomes a Subsidiary of the Borrower or any of its Restricted Subsidiaries shall be classified as a
Restricted Subsidiary.
The Borrower may designate any Subsidiary (including a newly formed or newly acquired Subsidiary) as an Unrestricted
(b)
Subsidiary if (i) the representations and warranties of the Borrower and its Restricted Subsidiaries contained in each of the Loan
Documents are true and correct on and as of such date as if made on and as of the date of such designation (or, if stated to have been
made expressly as of an earlier date, were true and correct as of such date), and
32
(ii) after giving effect to such designation, no Default or Event of Default would exist; provided, however, that the Borrower may not
designate EDC as an Unrestricted Subsidiary. Except as provided in this Section, no Restricted Subsidiary may be redesignated as an
Unrestricted Subsidiary.
The Borrower may designate any Unrestricted Subsidiary to be a Restricted Subsidiary if after giving effect to such
(c)
designation, (i) the representations and warranties of the Borrower and its Restricted Subsidiaries contained in each of the Loan
Documents are true and correct on and as of such date as if made on and as of the date of such redesignation (or, if stated to have been
made expressly as of an earlier date, were true and correct as of such date), and (ii) after giving effect to such designation, no Default
or Event of Default would exist.
SECTION 7.2 Negative Covenants. The Borrower agrees with the Agent and each Lender that, until all Commitments have
terminated and all Obligations have been paid and performed in full, the Borrower will perform the obligations set forth in this Section
7.2.
SECTION 7.2.1 Business Activities. The Borrower will not, and will not permit any of its Restricted Subsidiaries to, engage in any
business activity if, as a result thereof, the Borrower and its Restricted Subsidiaries taken as a whole would no longer be principally
engaged in the business of oil, gas and energy exploration, development, production, processing and marketing and such activities as
may be incidental or related thereto.
SECTION 7.2.2 Liens. The Borrower will not, and will not permit any of its Restricted Subsidiaries to, create, incur, assume or
suffer to exist any Lien upon any of its property, revenues or assets, whether now owned or hereafter acquired, except:
(a)
Liens securing payment of the Obligations, granted pursuant to any Loan Document;
Liens for taxes, assessments or other governmental charges or levies not at the time delinquent or thereafter payable without
(b)
penalty or being diligently contested in good faith by appropriate proceedings and for which adequate reserves in accordance with
GAAP shall have been set aside on its books;
(c)
Liens of carriers, warehousemen, mechanics, materialmen and landlords incurred in the ordinary course of business for sums
not overdue or being diligently contested in good faith by appropriate proceedings and for which adequate reserves in accordance with
GAAP shall have been set aside on its books;
Liens incurred in the ordinary course of business in connection with workmen’s compensation, unemployment insurance or
(d)
other forms of governmental insurance or benefits, or to secure performance of tenders, statutory obligations, leases and contracts
(other than for borrowed money) entered into in the ordinary course of business or to secure obligations on surety or appeal bonds;
judgment Liens in existence less than 30 days after the entry thereof or with respect to which execution has been stayed or
(e)
the payment of which is covered in full (subject to a customary deductible) by insurance maintained with responsible insurance
companies;
33
(f)
excess in the aggregate of $50,000,000 for all such cash and cash equivalents;
Liens on cash or cash−equivalents securing Hedging Obligations of the Borrower or any of its Restricted Subsidiaries not in
(g)
subdivision of any such jurisdiction to secure partial, progress, advance or other payments pursuant to any contract or statute;
Liens in favor of the United States of America or any state thereof or any department, agency, instrumentality or political
Liens required by any contract or statute in order to permit the Borrower or a Restricted Subsidiary to perform any contract
(h)
or subcontract made by it with or at the request of the United States of America, any state or any department, agency or
instrumentality or political subdivision of either;
Liens which exist prior to the time of acquisition upon any assets acquired by the Borrower or any Restricted Subsidiary
(i)
(including Liens on assets of any Person at the time of the acquisition of the capital stock or assets of such Person or a merger with or
consolidation with such Person by the Borrower or a Restricted Subsidiary), provided that (i) the Lien shall attach solely to the assets
so acquired (or of the Person so acquired, merged or consolidated), and (ii) in the case of Liens securing Indebtedness the aggregate
principal amount of all Indebtedness of Restricted Subsidiaries secured by such Liens shall be permitted by the limitations set forth in
Section 7.2.5;
(j)
(k)
(l)
Liens securing Indebtedness owing by any Restricted Subsidiary to the Borrower;
Liens under operating agreements, unitization agreements, pooling orders, and similar arrangements;
Liens set forth on Schedule 7.2 which are existing on the Effective Date;
(m)
Liens on debt of or equity interests in a Person that is not a Restricted Subsidiary;
Any extension, renewal or replacement (or successive extensions, renewals or replacements), in whole or in part, of any Lien
(n)
referred to in the foregoing clauses of this Section or of any Indebtedness secured thereby; provided that in the case of Liens securing
Indebtedness, the principal amount of Indebtedness secured thereby shall not exceed the principal amount of Indebtedness so secured
at the time of such extension, renewal or replacement and that such extension, renewal or replacement Lien shall be limited to all or
part of substantially the same property or revenue subject of the Lien extended, renewed or replaced (plus improvements on such
property); and
additional Liens upon assets of the Borrower and its Restricted Subsidiaries created after the date hereof, provided that (i) the
(o)
aggregate Indebtedness secured thereby and incurred on or after the date hereof shall not exceed two and one−half percent (2 ½%) of
Stockholders’ Equity in the aggregate at any one time outstanding and (ii) that such Liens do not encumber or attach to any equity
interest in a Restricted Subsidiary.
34
SECTION 7.2.3 Financial Covenants. The Borrower will not:
(a)
four fiscal quarters ending on the last day of a fiscal quarter to be less than 4.0:1.0.
EBITDAX to Total Interest Expense. Permit the ratio of EBITDAX to Total Interest Expense for any consecutive period of
(b)
time.
(c)
time.
Total Debt to Capitalization. Permit the Total Debt to Capitalization Ratio, expressed as a percentage, to exceed 60% at any
Minimum Total Asset Value. Permit the Total Asset Value of its Restricted Subsidiaries to be less than $800,000,000 at any
SECTION 7.2.4 Restricted Payments, etc. On and at all times after the Effective Date, the Borrower will not declare, pay or make
any dividend or distribution (in cash, property or obligations) on any shares of any class of capital stock (now or hereafter outstanding)
of the Borrower or on any warrants, options or other rights with respect to any shares of any class of capital stock (now or hereafter
outstanding) of the Borrower (other than dividends or distributions payable in its common stock or warrants to purchase its common
stock or splitups or reclassifications of its stock into additional or other shares of its common stock) or apply, or permit any of its
Restricted Subsidiaries to apply, any of its funds, property or assets to the purchase, redemption, sinking fund or other retirement of, or
agree or permit any of its Restricted Subsidiaries to purchase or redeem, any shares of any class of capital stock (now or hereafter
outstanding) of the Borrower, or warrants, options or other rights with respect to any shares of any class of capital stock (now or
hereafter outstanding) of the Borrower, if, after giving effect thereto, a Default or an Event of Default shall have occurred and be
continuing or been caused thereby.
SECTION 7.2.5 Indebtedness. The Borrower will not permit any of its Restricted Subsidiaries to contract, create, incur or assume
any Indebtedness, except:
(a)
Indebtedness of a Restricted Subsidiary owed to the Borrower or an other Restricted Subsidiary;
Indebtedness of a Restricted Subsidiary which exists prior to the time of the acquisition of such Subsidiary by the Borrower
(b)
or any Restricted Subsidiary (including Indebtedness at the time of the acquisition of the capital stock or assets of such Person or a
merger with or consolidation with such Person by the Borrower or a Restricted Subsidiary) and any extensions, renewals or
replacements of such Indebtedness, provided that the aggregate principal amount of such Indebtedness and any extensions, renewals
or replacements thereof shall not exceed the principal amount of such Indebtedness at the time such Person becomes a Subsidiary; and
(c)
other Indebtedness in an aggregate amount not to exceed an amount equal to five percent (5%) of Stockholders’ Equity.
SECTION 7.2.6 Consolidation, Merger, etc. The Borrower will not, and will not permit any of its Restricted Subsidiaries to,
liquidate or dissolve, consolidate with, or merge into or with, any other corporation, or purchase or otherwise acquire all or
substantially all of the
35
assets of any Person (or of any division thereof) except (a) any such Restricted Subsidiary may liquidate or dissolve voluntarily into,
and may merge with and into, the Borrower or any other Restricted Subsidiary, and the assets or stock of any Restricted Subsidiary
may be purchased or otherwise acquired by the Borrower or any other Restricted Subsidiary; and (b) so long as no Default or Event of
Default has occurred and is continuing or would occur after giving effect thereto, the Borrower or any of its Restricted Subsidiaries
may purchase all or substantially all of the assets of any Person, or acquire such Person by merger (as long as the Borrower or such
Restricted Subsidiary is the surviving entity).
SECTION 7.2.7 Negative Pledges, Restrictive Agreements, etc. The Borrower will not, and will not permit any of its Restricted
Subsidiaries to, enter into any agreement (excluding this Agreement, any other Loan Document and any agreement governing any
Indebtedness not prohibited under this Agreement) prohibiting the creation or assumption of any Lien upon its material properties,
revenues or assets, whether now owned or hereafter acquired, or the ability of the Borrower to amend or otherwise modify this
Agreement or any other Loan Document. The foregoing shall not prohibit agreements entered into or acquired in the ordinary course
of business regarding specific properties or assets which restrict or place conditions the transfer of or the creation of a Lien on such
properties or assets or the revenues derived therefrom, but which do not affect other unrelated properties, assets or revenues. The
Borrower will not and will not permit any of its Restricted Subsidiaries to enter into any agreement prohibiting the ability of any
Restricted Subsidiary to make any payments, directly or indirectly, to the Borrower by way of dividends, advances, repayments of
loans or advances, reimbursements of management and other intercompany charges, expenses and accruals or other returns on
investments, or any other agreement or arrangement which restricts the ability of any such Restricted Subsidiary to make any
payment, directly or indirectly, to the Borrower.
ARTICLE VIII
EVENTS OF DEFAULT
SECTION 8.1 Listing of Events of Default. Each of the following events or occurrences described in this Section 8.1 shall
constitute an “Event of Default”.
SECTION 8.1.1 Non−Payment of Obligations. The Borrower shall default in the payment or prepayment when due of any
principal of any Loan, or the Borrower shall default (and such default shall continue unremedied for a period of five days) in the
payment when due of any interest on any Loan, of any fee hereunder or of any other Obligation.
SECTION 8.1.2 Breach of Warranty. Any representation or warranty of the Borrower made or deemed to be made hereunder or
in any other Loan Document executed by it or any certificates delivered pursuant to Article V is or shall be incorrect in any material
respect when made or deemed made.
SECTION 8.1.3 Non−Performance of Certain Covenants and Obligations. The Borrower shall default in the due performance and
observance of any of its obligations under Section 7.2.2, 7.2.3, 7.2.6 or 7.2.7; provided that the imposition of any non−consensual
Lien that is not permitted to exist pursuant to Section 7.2.2 shall not be deemed to constitute an Event of Default hereunder until thirty
(30) days after the date of such imposition.
36
SECTION 8.1.4 Non−Performance of Other Covenants and Obligations. The Borrower shall default in the due performance and
observance of any other provision contained herein (not constituting an Event of Default under the preceding provisions of this
Section 8.1) or any other Loan Document executed by it, and such default shall continue unremedied for a period of 30 days after
notice thereof shall have been given to the Borrower by the Agent.
SECTION 8.1.5 Default on Other Indebtedness. A default shall occur in the payment when due (subject to any applicable grace
period), whether by acceleration or otherwise, of any Indebtedness (other than Indebtedness described in Section 8.1.1) of the
Borrower or any of its Restricted Subsidiaries having a principal amount, individually or in the aggregate, in excess of $35,000,000, or
a default shall occur in the performance or observance of any obligation or condition with respect to such Indebtedness if the effect of
such default is to accelerate the maturity of any such Indebtedness or such default shall continue unremedied for any applicable period
of time sufficient to permit the holder or holders of such Indebtedness, or any trustee or agent for such holders, to cause such
Indebtedness to become due and payable prior to its expressed maturity.
SECTION 8.1.6 Judgments. Any judgment or order for the payment of money in excess of $35,000,000 shall be rendered against
the Borrower or any of its Restricted Subsidiaries if such excess is not fully covered by valid and collectible insurance in respect
thereof, the payment of which is not being disputed or contested by the insurer or the insurers, and either (i) proper or valid
enforcement or levying proceedings shall have been commenced by any creditor upon such judgment or order or (ii) such judgment or
order shall continue unsatisfied and unstayed for a period of thirty (30) consecutive days.
SECTION 8.1.7 Pension Plans. Any of the following events shall occur with respect to any Pension Plan (a) the institution of any
steps by the Borrower, any member of its Controlled Group or any other Person to terminate a Pension Plan if, as a result of such
termination, the Borrower or any such member could be required to make a contribution to such Pension Plan in excess of
$35,000,000; or (b) a contribution failure occurs with respect to any Pension Plan sufficient to give rise to a Lien under section 302(f)
of ERISA to the extent such action could reasonably be expected to have a Material Adverse Effect.
SECTION 8.1.8 Change in Control. Any Change in Control shall occur.
SECTION 8.1.9 Bankruptcy, Insolvency, etc. The Borrower or any of its Restricted Subsidiaries shall (a) become insolvent or
generally fail to pay, or admit in writing its inability or unwillingness to pay, debts as they become due; (b) apply for, consent to, or
acquiesce in, the appointment of a trustee, receiver, sequestrator or other custodian for the Borrower or any of its Restricted
Subsidiaries or any substantial portion of the property of any thereof, or make a general assignment for the benefit of creditors; (c) in
the absence of such application, consent or acquiescence, permit or suffer to exist the appointment of a trustee, receiver, sequestrator
or other custodian for the Borrower or any of its Restricted Subsidiaries or for a substantial part of the property of any thereof, and
such trustee, receiver, sequestrator or other custodian shall not be discharged within 60 days, provided that the Borrower, each
Restricted Subsidiary hereby expressly authorizes the Agent and each Lender to appear in any court conducting any relevant
proceeding during such 60−day period to preserve, protect and defend their rights under the Loan
37
Documents; (d) permit or suffer to exist the commencement of any bankruptcy, reorganization, debt arrangement or other case or
proceeding under any bankruptcy or insolvency law, or any dissolution, winding up or liquidation proceeding, in respect of the
Borrower or any of its Restricted Subsidiaries, and, if any such case or proceeding is not commenced by the Borrower or such
Subsidiary, such case or proceeding shall be consented to or acquiesced in by the Borrower or such Restricted Subsidiary or shall
result in the entry of an order for relief or shall remain for 60 days undismissed, provided that the Borrower, each Restricted
Subsidiary hereby expressly authorizes the Agent and each Lender to appear in any court conducting any such case or proceeding
during such 60−day period to preserve, protect and defend their rights under the Loan Documents; or (e) take any corporate action
authorizing, or in furtherance of, any of the foregoing.
Action if Bankruptcy. If any Event of Default described in Section 8.1.9 shall occur with respect to the
SECTION 8.2
Borrower or any Restricted Subsidiary, the Commitments (if not theretofore terminated) shall automatically terminate and the
outstanding principal amount of all outstanding Borrowings and all other Obligations shall automatically be and become immediately
due and payable, without notice or demand.
Action if Other Event of Default. If any Event of Default (other than any Event of Default described in
SECTION 8.3
Section 8.1.9 with respect to the Borrower or any Restricted Subsidiary) shall occur for any reason, whether voluntary or involuntary,
and be continuing, the Agent, upon the direction of the Required Lenders, shall by notice to the Borrower declare all or any portion of
the outstanding principal amount of the Borrowings and other Obligations to be due and payable and/or the Commitments (if not
theretofore terminated) to be terminated, whereupon the full unpaid amount of such Loans and other Obligations which shall be so
declared due and payable shall be and become immediately due and payable, without further notice, demand or presentment, as the
case may be, and/or the Commitments shall terminate.
ARTICLE IX
THE AGENTS
Actions. Each Lender hereby appoints (i) JPMorgan as the Agent under this Agreement and each other Loan
SECTION 9.1
Document, (ii) Wachovia Bank, National Association, as Syndication Agent under this Agreement and each other Loan Document,
(iii) Société Générale, Deutsche Bank AG New York Branch and The Royal Bank of Scotland plc, as Co−Documentation Agents
under this Agreement and each other Loan Document, and (iv) the entities identified as “Senior Managing Agents” on the signature
pages to this Agreement as senior managing agents under this Agreement and each other Loan Document. Each Lender authorizes the
Agent to act on behalf of such Lender under this Agreement and each other Loan Document and, in the absence of other written
instructions from the Required Lenders received from time to time by the Agent (with respect to which the Agent agrees that it will
comply, except as otherwise provided in this Section or as otherwise advised by counsel), to exercise such powers hereunder and
thereunder as are specifically delegated to or required of the Agent by the terms hereof and thereof, together with such powers as may
be reasonably incidental thereto. Each Lender acknowledges that none of the Syndication Agent, the Co−Documentation Agents or
the Senor Managing Agents have any duties or obligations under this Agreement or any other Loan Document in connection with their
capacity as either the Syndication Agent, a Co−Documentation Agent or a Senior Managing Agent, respectively.
38
Each Lender hereby indemnifies (which indemnity shall survive any termination of this Agreement) each of the Agents, pro rata
according to such Lender’s Percentage, WHETHER OR NOT RELATED TO ANY SINGULAR, JOINT OR CONCURRENT
NEGLIGENCE OF THE AGENTS, from and against any and all liabilities, obligations, losses, damages, claims, costs or expenses
of any kind or nature whatsoever which may at any time be imposed on, incurred by, or asserted against, any Agent in any way
relating to or arising out of this Agreement and any other Loan Document, including reasonable attorneys’ fees, and as to which such
Agent is not reimbursed by the Borrower; provided, however, that no Lender shall be liable for the payment of any portion of such
liabilities, obligations, losses, damages, claims, costs or expenses which are determined by a court of competent jurisdiction in a final
proceeding to have resulted solely from such Agent’s gross negligence or willful misconduct. None of the Agents shall be required to
take any action hereunder or under any other Loan Document, or to prosecute or defend any suit in respect of this Agreement or any
other Loan Document, unless it is indemnified hereunder to its satisfaction. If any indemnity in favor of any Agent shall be or become
inadequate, in such Agent’s determination, as the case may be, such Agent may call for additional indemnification from the Lenders
and cease to do the acts indemnified against hereunder until such additional indemnity is given. Notwithstanding any provision to the
contrary contained elsewhere in this Agreement or in any other Loan Document, none of the Agents shall have any duties or
responsibilities, except as expressly set forth herein, nor shall any of the Agents have or be deemed to have any fiduciary relationship
with any Lender, and no implied covenants, functions, responsibilities, duties, obligations or liabilities shall be read into this
Agreement or any other Loan Document or otherwise exist against any of the Agents.
Funding Reliance, etc. Unless the Agent shall have been notified by telephone, confirmed in writing, by any
SECTION 9.2
Lender by 5:00 p.m., Central time, on the day prior to a Borrowing (except with respect to a Borrowing comprised of Base Rate
Loans, in which case notice shall be given no later than 12:00 noon, Central time, on the date of the proposed Borrowing) that such
Lender will not make available the amount which would constitute its Percentage of such Borrowing on the date specified therefor, the
Agent may assume that such Lender has made such amount available to the Agent and, in reliance upon such assumption, make
available to the Borrower a corresponding amount. If and to the extent that such Lender shall not have made such amount available to
the Agent, such Lender and the Borrower severally agree to repay the Agent forthwith on demand such corresponding amount together
with interest thereon, for each day from the date the Agent made such amount available to the Borrower to the date such amount is
repaid to the Agent, at the Federal Funds Rate.
Exculpation. None of the Agents and their respective directors, officers, employees or agents shall be liable to
SECTION 9.3
any Lender for any action taken or omitted to be taken by it under this Agreement or any other Loan Document, or in connection
herewith or therewith, except for its own willful misconduct or gross negligence, nor responsible for any recitals or warranties herein
or therein, nor for the effectiveness, enforceability, validity or due execution of this Agreement or any other Loan Document, nor to
make any inquiry respecting the performance by the Borrower of its obligations hereunder or under any other Loan Document. Any
such inquiry which may be made by any Agent shall not obligate it to make any further inquiry or to take any action. Each of the
Agents shall be entitled to rely upon advice of
39
counsel concerning legal matters and upon any notice, consent, certificate, statement or writing which such Agent believes to be
genuine and to have been presented by a proper Person.
Successor. Any of the Agents may resign as such at any time upon at least 30 days’ prior notice to the
SECTION 9.4
Borrower and all Lenders. If the Agent at any time shall resign, the Required Lenders may appoint another Lender as the successor
Agent which shall thereupon become the Agent hereunder. If no successor Agent shall have been so appointed by the Required
Lenders, and shall have accepted such appointment, within 30 days after the retiring Agent’s giving notice of resignation, then the
retiring Agent may, on behalf of the Lenders, appoint a successor Agent, which shall be one of the Lenders or a commercial banking
institution organized under the laws of the U.S. (or any State thereof) or a U.S. branch or agency of a commercial banking institution,
and having a combined capital and surplus of at least $500,000,000. Upon the acceptance of any appointment as the Agent hereunder
by a successor Agent, such successor Agent shall be entitled to receive from the retiring Agent such documents of transfer and
assignment as such successor Agent may reasonably request, and shall thereupon succeed to and become vested with all rights,
powers, privileges and duties of the retiring Agent, and the retiring Agent shall be discharged from its duties and obligations under this
Agreement. After a retiring Agent’s resignation hereunder as a Agent, the provisions of this Article IX shall inure to its benefit as to
any actions taken or omitted to be taken by it while it was the Agent under this Agreement, and Section 10.4 (and, with respect to the
Agent, Section 10.3) shall continue to inure to its benefit.
Loans by the Agents. Each of the Agents shall have the same rights and powers with respect to the Loans
SECTION 9.5
made by it or any of its Affiliates and may exercise the same as if it were not a Agent. Each of the Agents and its Affiliates may
accept deposits from, lend money to, and generally engage in any kind of business with the Borrower or any Subsidiary or Affiliate of
the Borrower as if it were not a Agent hereunder.
Credit Decisions. Each Lender acknowledges that it has made its own credit decision to extend its
SECTION 9.6
Commitments hereunder (i) independently of each of the Agents and each other Lender, and (ii) based on such Lender’s review of the
financial information of the Borrower, this Agreement, the other Loan Documents (the terms and provisions of which being
satisfactory to such Lender) and such other documents, information and investigations as such Lender has deemed appropriate. Each
Lender also acknowledges that it will continue to make its own credit decisions as to exercising or not exercising from time to time
any rights and privileges available to it under this Agreement or any other Loan Document (i) independently of each of the Agents and
each other Lender, and (ii) based on such other documents, information and investigations as it shall deem appropriate at any time.
Copies, etc. The Agent shall give prompt notice to each Lender of each notice or request required or
SECTION 9.7
permitted to be given to the Agent by the Borrower pursuant to the terms of this Agreement (unless concurrently delivered to the
Lenders by the Borrower). The Agent will distribute to each Lender each document or instrument received for its account and copies
of all other communications received by the Agent from the Borrower for distribution to the Lenders by the Agent in accordance with
the terms of this Agreement.
40
ARTICLE X
MISCELLANEOUS PROVISIONS
Waivers, Amendments, etc. The provisions of this Agreement and of each other Loan Document may from
SECTION 10.1
time to time be amended, modified or waived, if such amendment, modification or waiver is in writing and consented to by the
Borrower and the Required Lenders; provided, however, that no such amendment, modification or waiver which would: (a) modify
any requirement hereunder that any particular action be taken by all the Lenders or by the Required Lenders shall be effective unless
consented to by each Lender; (b) modify this Section 10.1, change the definition of “Required Lenders”, reduce any fees described in
Article III or extend the Maturity Date, shall be made without the consent of each Lender; (c) extend the due date for, or reduce the
amount of, any scheduled repayment or prepayment of principal of or interest on any Loan (or reduce the principal amount of or rate
of interest on any Loan) shall be made without the consent of the Lender which made such Loan; or (d) affect adversely the interests,
rights or obligations of any Agent as Agent shall be made without the consent of such Agent; provided, further, that no such
amendment, modification or waiver which would either increase any Commitment, Commitment Amount or the Percentage of any
Lender, or modify the rights, duties or obligations of any Agent, shall be effective without the consent of such Lender or such Agent,
as applicable. No failure or delay on the part of the Agent or any Lender in exercising any power or right under this Agreement or any
other Loan Document shall operate as a waiver thereof, nor shall any single or partial exercise of any such power or right preclude any
other or further exercise thereof or the exercise of any other power or right. No notice to or demand on the Borrower in any case shall
entitle it to any notice or demand in similar or other circumstances. No waiver or approval by the Agent or any Lender under this
Agreement or any other Loan Document shall, except as may be otherwise stated in such waiver or approval, be applicable to
subsequent transactions. No waiver or approval hereunder shall require any similar or dissimilar waiver or approval thereafter to be
granted hereunder.
SECTION 10.2
Notices.
Except in the case of notices and other communications expressly permitted to be given by telephone, all notices and other
(a)
communications provided for herein shall be in writing and shall be delivered by hand or overnight courier service, mailed by certified
or registered mail or sent by telecopy, as follows:
(i)
if to the Borrower, to:
Noble Energy, Inc.
350 Glenborough, Suite 100
Houston, TX 77067
Attention:
Telephone No.:
Facsimile No.:
James L. McElvany
(281) 872−3100
(281) 872−3111
(ii)
if to the Agent, to:
41
Agency Services
JPMorgan Chase Bank
One Chase Manhattan Plaza, 8th Floor
New York, NY
10081
Attention:
Telephone No.:
Facsimile No.:
Muniram Appanna
(212) 552−7943
(212) 552−3295
With a copy to:
JPMorgan Chase Bank
Global Oil & Gas Group
600 Travis, 20th Floor
Houston, Texas 77002
Attention:
Telephone:
Facsimile:
Peter Licalzi
713−216−8869
713−216−4117
And in connection with business−related matters, with a copy to:
JPMorgan Chase Bank
Global Oil & Gas Group
600 Travis, 20th Floor
Houston, Texas 77002
Attention:
Telephone:
Facsimile:
Robert C. Mertensotto
713−216−4147
713−216−8870
(iii)
provided to the Agent and the Borrower or as set forth in its Administrative Questionnaire.
if to the Syndication Agent, any Co−Documentation Agent or any other Lender, to it at its address (or telecopy number)
Notices and other communications to the Lenders hereunder may be delivered or furnished by electronic communications
(b)
pursuant to procedures approved by the Administrative Agent; provided that the foregoing shall not apply to notices pursuant to
Article II unless otherwise agreed by the Administrative Agent and the applicable Lender. The Administrative Agent or the Borrower
may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to
procedures approved by it; provided that approval of such procedures may be limited to particular notices or communications.
Any party hereto may change its address or telecopy number for notices and other communications hereunder by notice to
(c)
the other parties hereto. All notices and other communications given to any party hereto in accordance with the provisions of this
Agreement shall be deemed to have been given on the date of receipt.
SECTION 10.3
costs and expenses of (i) the Agent (including, without limitation, the reasonable fees and out−of−pocket expenses of Mayer, Brown,
Rowe & Maw LLP) in connection with the preparation, negotiation, execution, delivery, syndication and
Payment of Costs, Expenses and Taxes. The Borrower agrees to pay on demand all reasonable out−of−pocket
42
administration of this Agreement and of each other Loan Document, including schedules and exhibits, and any amendments, waivers,
consents, supplements or other modification to this Agreement or any other Loan Document and (ii) the Agent and the Lenders in
connection with the enforcement by the Lenders or the Agent of, or the protection of rights under, this Agreement and each other Loan
Document. The Agent, the other Agents, the Arranger and each Lender agree to the extent feasible, and to the extent a conflict of
interest does not exist in the reasonable opinion of the Agent, the other Agents, the Arranger or any Lender, to use one law firm in
each jurisdiction in connection with the foregoing, to the extent they seek reimbursement for the expenses thereof from the Borrower.
Each Lender agrees to reimburse the Agent on demand for such Lender’s pro rata share (based upon its respective Percentage) of any
such costs or expenses not paid by the Borrower. In addition, the Borrower agrees to pay, and to save the Agent, the other Agents, the
Arranger, and the Lenders harmless from all liability for, any stamp or other taxes which may be payable in connection with the
execution or delivery of this Agreement, the Borrowings hereunder, or of any other instruments or documents provided for herein or
delivered or to be delivered hereunder or in connection herewith.
Indemnification. In consideration of the execution and delivery of this Agreement by each Lender and the
SECTION 10.4
extension of the Commitments, the Borrower hereby indemnifies, exonerates and holds each Agent, the Arranger and each Lender and
each of their respective officers, directors, employees and agents (collectively, the “Indemnified Parties”), WHETHER OR NOT
RELATED TO ANY NEGLIGENCE OF THE INDEMNIFIED PARTIES, free and harmless from and against any and all
actions, causes of action, suits, losses, costs, liabilities and damages, and expenses incurred in connection therewith (irrespective of
whether any such Indemnified Party is a party to the action for which indemnification hereunder is sought), including reasonable
attorneys’ fees and disbursements (collectively, the “Indemnified Liabilities”), incurred by the Indemnified Parties or any of them as a
result of, or arising out of, or relating to any transaction financed or to be financed in whole or in part, directly or indirectly, with the
proceeds of any Loan; the entering into and performance of this Agreement and any other Loan Document by any of the Indemnified
Parties; any investigation, litigation or proceeding related to any acquisition or proposed acquisition by the Borrower or any of its
Restricted Subsidiaries of all or any portion of the stock or assets of any Person, whether or not such Agent, the Arranger or such
Lender is party thereto; any investigation, litigation or proceeding related to any environmental cleanup, audit, compliance or other
matter relating to the protection of the environment or the Release by the Borrower or any of its Restricted Subsidiaries of any
Hazardous Material; or the presence on or under, or the escape, seepage, leakage, spillage, discharge, emission, discharging or releases
from, any real property owned or operated by the Borrower or any Subsidiary thereof of any Hazardous Material (including any
losses, liabilities, damages, injuries, costs, expenses or claims asserted or arising under any Environmental Law), regardless of
whether caused by, or within the control of, the Borrower or such Subsidiary, except for any such Indemnified Liabilities which are
determined by a court of competent jurisdiction in a final proceeding to have resulted solely from the relevant Indemnified Party’s
gross negligence or willful misconduct. If and to the extent that the foregoing undertaking may be unenforceable for any reason, the
Borrower hereby agrees to make the maximum contribution to the payment and satisfaction of each of the Indemnified Liabilities
which is permissible under applicable law.
43
SECTION 10.5
of the Lenders under Section 9.1, shall in each case survive any termination of this Agreement, the payment in full of all Obligations
and the termination of all Commitments.
Survival. The obligations of the Borrower under Sections 4.3, 4.4, 4.5, 4.6, 10.3 and 10.4, and the obligations
Severability. Any provision of this Agreement or any other Loan Document which is prohibited or
SECTION 10.6
unenforceable in any jurisdiction shall, as to such provision and such jurisdiction, be ineffective to the extent of such prohibition or
unenforceability without invalidating the remaining provisions of this Agreement or such Loan Document or affecting the validity or
enforceability of such provision in any other jurisdiction.
SECTION 10.7
convenience only and shall not affect the meaning or interpretation of this Agreement or such other Loan Document or any provisions
hereof or thereof.
Headings. The various headings of this Agreement and of each other Loan Document are inserted for
Governing Law; Entire Agreement. THIS AGREEMENT AND EACH OTHER LOAN DOCUMENT
SECTION 10.8
SHALL EACH BE DEEMED TO BE A CONTRACT MADE UNDER AND GOVERNED BY THE INTERNAL LAWS OF
THE STATE OF TEXAS, WITHOUT GIVING EFFECT TO PRINCIPLES OF CONFLICTS OF LAWS. This Agreement
and the other Loan Documents constitute the entire understanding among the parties hereto with respect to the subject matter hereof
and supersede any prior agreements, written or oral, with respect thereto.
SECTION 10.9
Successors and Assigns. This Agreement shall be binding upon and shall inure to the benefit of the parties
hereto and their respective successors and assigns; provided, however, that: (a) the Borrower may not assign or transfer its rights or
obligations hereunder without the prior written consent of the Agent and all Lenders; and (b) the rights of sale, assignment and transfer
of the Lenders are subject to Section 10.10.
SECTION 10.10
assign, or sell participations in, its Loans and Commitments to one or more other Persons in accordance with this Section.
Sale and Transfer of Loans and Commitments; Participations in Loans and Commitments. Each Lender may
Assignments. Any Lender (a) with the written consents of the Borrower (provided that the consent of
SECTION 10.10.1
the Borrower shall not be required if an Event of Default has occurred and is continuing) and the Agent (which consents of the
Borrower, if applicable, and the Agent shall not be unreasonably delayed or withheld), may at any time assign and delegate to one or
more commercial banks or other financial institutions, and (b) with notice to the Borrower and the Agent, but without the consent of
the Borrower or the Agent, may assign and delegate to any of its Affiliates or to any other Lender or Lender Affiliate (each Person
described in either of the foregoing clauses as being the Person to whom such assignment and delegation is to be made, being
hereinafter referred to as an “Assignee Lender”), all or any fraction of such Lender’s total Loans and Commitments (which assignment
and delegation shall be of a constant, and not a varying, percentage of all the assigning Lender’s Loans and Commitments and which
shall be of equal pro rata shares of the Facility) in a minimum aggregate amount of $5,000,000; provided, however, that any such
Assignee Lender will
44
comply, if applicable, with the provisions contained in the last sentence of Section 4.6 and further, provided, however, that, the
Borrower and the Agent shall be entitled to continue to deal solely and directly with such Lender in connection with the interests so
assigned and delegated to an Assignee Lender until (i) written notice of such assignment and delegation, together with payment
instructions, addresses and related information with respect to such Assignee Lender, shall have been given to the Borrower and the
Agent by such Lender and such Assignee Lender, (ii) such Assignee Lender shall have executed and delivered to the Borrower and the
Agent a Lender Assignment Agreement, accepted by the Agent, (iii) such Assignee Lender shall have delivered to the Agent an
Administrative Questionnaire, and (iii) the processing fees described below shall have been paid.
From and after the date that the Agent accepts such Lender Assignment Agreement, (x) the Assignee Lender thereunder shall be
deemed automatically to have become a party hereto and to the extent that rights and obligations hereunder have been assigned and
delegated to such Assignee Lender in connection with such Lender Assignment Agreement, shall have the rights and obligations of a
Lender hereunder and under the other Loan Documents, and (y) the assignor Lender, to the extent that rights and obligations
hereunder have been assigned and delegated by it in connection with such Lender Assignment Agreement, shall be released from its
obligations hereunder and under the other Loan Documents. Accrued interest on that part of the predecessor Loans and
Commitments, and accrued fees, shall be paid as provided in the Lender Assignment Agreement. Accrued interest on that part of the
predecessor Loans and Commitments shall be paid to the assignor Lender. Accrued interest and accrued fees shall be paid at the same
time or times provided in this Agreement. Such assignor Lender or such Assignee Lender must also pay a processing fee to the Agent
upon delivery of any Lender Assignment Agreement in the amount of $3,500. Any attempted assignment and delegation not made in
accordance with this Section shall be null and void.
Participations. Any Lender may at any time sell to one or more commercial banks or other Persons
SECTION 10.10.2
(each of such commercial banks and other Persons being herein called a “Participant”) participating interests in any of the Loans,
Commitments or other interests of such Lender hereunder; provided, however, that (a) no participation contemplated in this
Section 10.10 shall relieve such Lender from its Commitments or its other obligations hereunder or under any other Loan Document,
(b) such Lender shall remain solely responsible for the performance of its Commitments and such other obligations, (c) the Borrower
and the Agent shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations
under this Agreement and each of the other Loan Documents, (d) no Participant, unless such Participant is an Affiliate of such Lender,
or is itself a Lender, shall be entitled to require such Lender to take or refrain from taking any action hereunder or under any other
Loan Document, except that such Lender may agree with any Participant that such Lender will not, without such Participant’s consent,
take any actions of the type described in clause (b) or (c) of Section 10.1, and (e) the Borrower shall not be required to pay any amount
under Section 4.6 that is greater than the amount which it would have been required to pay had no participating interest been sold.
The Borrower acknowledges and agrees that each Participant, for purposes of Sections 4.3, 4.4, 4.5, 4.6, 4.7, 4.8, 4.9 and 10.4, shall be
considered a Lender; provided that this sentence shall not obligate the Borrower to pay more under such Sections that it would be
obligated to pay had no such participation been granted.
45
Pledge by Lender. Any Lender may at any time pledge or assign a security interest in all or any portion
SECTION 10.10.3
of its rights under this Agreement to secure obligations of such Lender, including any pledge or assignment to secure obligations to a
Federal Reserve Bank, and this Section shall not apply to any such pledge or assignment of a security interest; provided that no such
pledge or assignment of a security interest shall release a Lender from any of its obligations hereunder or substitute any such pledgee
or assignee for such Lender as a party hereto.
SECTION 10.11
any transaction, in addition to those contemplated by this Agreement or any other Loan Document, with the Borrower or any of its
Affiliates in which the Borrower or such Affiliate is not restricted hereby from engaging with any other Person.
Other Transactions. Nothing contained herein shall preclude the Agent or any other Lender from engaging in
Confidentiality. Each of the Agents and the Lenders agrees to maintain the confidentiality of the Information
SECTION 10.12
(as defined below), except that Information may be disclosed (a) to its and its Affiliates’ directors, officers, employees and agents,
including accountants, legal counsel and other advisors (it being understood that the Persons to whom such disclosure is made will be
informed of the confidential nature of such Information and instructed to keep such Information confidential), (b) to the extent
requested by any regulatory authority or self−regulatory body, (c) to the extent required by applicable laws or regulations or by any
subpoena or similar legal process, (d) to any other party to this Agreement, (e) in connection with the exercise of any remedies
hereunder or any suit, action or proceeding relating to this Agreement or any other Loan Document or the enforcement of rights
hereunder or thereunder, (f) subject to an agreement containing provisions substantially the same as those of this Section, to (i) any
assignee of or Participant in, or any prospective assignee of or Participant in, any of its rights or obligations under this Agreement or
(ii) any actual or prospective counterparty (or its advisors) to any Hedging Agreement, (g) with the consent of Borrower or (h) to the
extent such Information (i) becomes publicly available other than as a result of a breach of this Section by any Person or (ii) becomes
available to any Agent or any Lender on a nonconfidential basis from a source other than Borrower or any of its Affiliates. For the
purposes of this Section, “Information” means all information received from Borrower or its Affiliate relating to Borrower and its
Subsidiaries or their business, other than any such information that is available to any Agent or any Lender on a nonconfidential basis
prior to disclosure by Borrower or any of its Affiliates. Any Person required to maintain the confidentiality of Information as
provided in this Section shall be considered to have complied with its obligation to do so if such Person has exercised the same degree
of care to maintain the confidentiality of such Information as such Person would accord to its own confidential information.
Furthermore, this obligation of confidentiality shall not apply to, and each of the Agents and the Lenders (and each Person employed
or retained by such Agents or Lenders who are or are expected to become engaged in evaluating, approving, structuring or
administering the Loans) may disclose to any Person, without limitation of any kind, the “tax treatment” and “tax structure” (in each
case, within the meaning of Treasury Regulation Section 1.6011−4) of the Loan transactions contemplated by this Agreement and the
other Loan Documents, and all materials of any kind (including opinions or other tax analyses) related thereto that are or have been
provided to such Agent or Lender relating to such tax treatment or tax structure. With respect to any document or similar item that in
either case contains confidential information concerning such tax treatment or tax structure of
46
the Loan transactions contemplated by this Agreement and the other the Loan Documents as well as other information, the prior
sentence shall only apply to such portions of the documents or similar item that relate to such tax treatment or tax structure.
Forum Selection and Consent to Jurisdiction. ANY LITIGATION BASED HEREON, OR ARISING
SECTION 10.13
OUT OF, UNDER, OR IN CONNECTION WITH, THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT, OR ANY
COURSE OF CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER VERBAL OR WRITTEN) OR ACTIONS
OF THE AGENT, THE LENDERS OR THE BORROWER SHALL BE BROUGHT AND MAINTAINED EXCLUSIVELY
IN THE COURTS OF THE STATE OF TEXAS OR IN THE UNITED STATES DISTRICT COURT FOR THE SOUTHERN
DISTRICT OF TEXAS; PROVIDED, HOWEVER, THAT ANY SUIT SEEKING ENFORCEMENT AGAINST ANY
COLLATERAL OR OTHER PROPERTY MAY BE BROUGHT, AT THE AGENT’S OPTION, IN THE COURTS OF ANY
JURISDICTION WHERE SUCH COLLATERAL OR OTHER PROPERTY MAY BE FOUND. THE BORROWER, THE
AGENT, AND EACH LENDER HEREBY EXPRESSLY AND IRREVOCABLY SUBMIT TO THE JURISDICTION OF
THE COURTS OF THE STATE OF TEXAS AND OF THE UNITED STATES DISTRICT COURT FOR THE SOUTHERN
DISTRICT OF TEXAS FOR THE PURPOSE OF ANY SUCH LITIGATION AS SET FORTH ABOVE AND
IRREVOCABLY AGREE TO BE BOUND BY ANY JUDGMENT RENDERED THEREBY IN CONNECTION WITH
SUCH LITIGATION. THE BORROWER, THE AGENT, AND EACH LENDER FURTHER IRREVOCABLY CONSENT
TO THE SERVICE OF PROCESS BY REGISTERED MAIL, POSTAGE PREPAID, OR BY PERSONAL SERVICE
WITHIN OR WITHOUT THE STATE OF TEXAS. THE BORROWER, THE AGENT, AND EACH LENDER HEREBY
EXPRESSLY AND IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY OBJECTION
WHICH IT MAY HAVE OR HEREAFTER MAY HAVE TO THE LAYING OF VENUE OF ANY SUCH LITIGATION
BROUGHT IN ANY SUCH COURT REFERRED TO ABOVE AND ANY CLAIM THAT ANY SUCH LITIGATION HAS
BEEN BROUGHT IN AN INCONVENIENT FORUM. TO THE EXTENT THAT THE BORROWER HAS OR
HEREAFTER MAY ACQUIRE ANY IMMUNITY FROM JURISDICTION OF ANY COURT OF FROM ANY LEGAL
PROCESS (WHETHER THROUGH SERVICE OR NOTICE, ATTACHMENT PRIOR TO JUDGMENT, ATTACHMENT
IN AID OF EXECUTION OR OTHERWISE) WITH RESPECT TO ITSELF OR ITS PROPERTY, THE BORROWER
HEREBY IRREVOCABLY WAIVES SUCH IMMUNITY IN RESPECT OF ITS OBLIGATIONS UNDER THIS
AGREEMENT AND THE OTHER LOAN DOCUMENTS.
Waiver of Jury Trial. THE AGENT, THE LENDERS AND THE BORROWER HEREBY
SECTION 10.14
KNOWINGLY, VOLUNTARILY AND INTENTIONALLY WAIVE ANY RIGHTS THEY MAY HAVE TO A TRIAL BY
JURY IN RESPECT OF ANY LITIGATION BASED HEREON, OR ARISING OUT OF, UNDER, OR IN CONNECTION
WITH, THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT, OR ANY COURSE OF CONDUCT, COURSE OF
DEALING, STATEMENTS (WHETHER VERBAL OR WRITTEN) OR ACTIONS OF THE AGENT, THE LENDERS OR
THE BORROWER. THE BORROWER ACKNOWLEDGES AND
47
AGREES THAT IT HAS RECEIVED FULL AND SUFFICIENT CONSIDERATION FOR THIS PROVISION (AND EACH
OTHER PROVISION OF EACH OTHER LOAN DOCUMENT TO WHICH IT IS A PARTY) AND THAT THIS
PROVISION IS A MATERIAL INDUCEMENT FOR THE AGENT AND THE LENDERS ENTERING INTO THIS
AGREEMENT AND EACH SUCH OTHER LOAN DOCUMENT.
SECTION 10.15
NO ORAL AGREEMENTS. THIS WRITTEN AGREEMENT AND THE OTHER LOAN DOCUMENTS
REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES WITH RESPECT TO THE SUBJECT MATTER HEREOF
AND THEREOF AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR
SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG
THE PARTIES.
[SIGNATURES BEGIN ON FOLLOWING PAGE]
48
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly
authorized as of the day and year first above written.
NOBLE ENERGY, INC., the Borrower
By:
Name:
Title:
[SIGNATURE PAGE TO NOBLE ENERGY, INC.
364−DAY CREDIT AGREEMENT]
S − 1
JPMORGAN CHASE BANK, individually as a Lender, as
the Administrative Agent and as a Senior Managing Agent
By:
Name:
Title:
S − 2
WACHOVIA BANK, NATIONAL ASSOCIATION,
individually as a Lender, as the Syndication Agent and as a
Senior Managing Agent
By:
Name:
Title:
S − 3
SOCIÉTÉ GÉNÉRALE, individually as a Lender, as a
Co−Documentation Agent and as a Senior Managing Agent
By:
Name:
Title:
S − 4
CITICORP USA, INC., individually as a Senior Managing
Agent and as a Lender
By:
Name:
Title:
S − 5
DEUTSCHE BANK AG NEW YORK BRANCH,
individually as a Lender, as a Co−Documentation Agent and as
a Senior Managing Agent
By:
Name:
Title:
By:
Name:
Title:
S − 6
THE ROYAL BANK OF SCOTLAND PLC, individually as
a Lender, as a Co−Documentation Agent and as a Senior
Managing Agent
By:
Name:
Title:
S − 7
BNP PARIBAS, individually as a Lender and as a Co−Agent
By:
Name:
Title:
S − 8
THE BANK OF NEW YORK, individually as a Lender
By:
Name:
Title:
S − 9
COMPASS BANK, individually as a Lender
By:
Name:
Title:
S − 10
WELLS FARGO BANK, N.A., individually as a Lender
By:
Name:
Title:
S − 11
BMO NESBITT BURNS FINANCING, INC., individually
as a Lender
By:
Name:
Title:
S − 12
BANK ONE, N.A., individually as a Lender and as a Senior
Managing Agent
By:
Name:
Title:
S − 13
COMERICA BANK, individually as a Lender
By:
Name:
Title:
[SIGNATURE PAGE TO NOBLE ENERGY, INC.
364−DAY CREDIT AGREEMENT]
S − 14
MORGAN STANLEY BANK, individually as a Lender
By:
Name:
Title:
S − 15
SOUTHWEST BANK OF TEXAS, N.A, individually as a Lender
By:
Name:
Title:
S − 16
SUMITOMO MITSUI BANKING CORPORATION, individually
as a Lender and as a Senior Managing Agent
By:
Name:
Title:
S − 17
KBC BANK NV, individually as a Lender
By:
Name:
Title:
By:
Name:
Title:
S − 18
BARCLAYS BANK PLC, individually as a
Lender and as a Senior Managing Agent
By:
Name:
Title:
S − 19
MIZUHO CORPORATE BANK, LTD., individually as a
Co−Agent and as a Lender
By:
Name:
Title:
S − 20
BAYERISCHE LANDESBANK, CAYMAN ISLANDS
BRANCH, individually as a Lender
By:
Name:
Title:
By:
Name:
Title:
S − 21
THE BANK OF TOKYO−MITSUBISHI, LTD., individually as a
Lender
By:
Name:
Title:
S − 22
DEN NORSKE BANK ASA, individually as a Lender
By:
Name:
Title:
S − 23
DISCLOSURE SCHEDULE
SCHEDULE I
ITEM 5.1.5 Material Adverse Change. None.
ITEM 6.5 Financial Information. None.
ITEM 6.7 Litigation. None.
ITEM 6.10 Employee Benefit Plans. Noble Energy, Inc. provide subsidized health care and life insurance benefits to their
early retirees (retirees who have completed at least twenty years of service or retirees who have attained age 55 and completed at least
five years of service) for the period of their retirement prior to attaining age 65.
1
SCHEDULE OF COMMITMENTS
SCHEDULE II
NAME OF LENDER
JPMorgan Chase Bank
Wachovia Bank, National Association
The Royal Bank of Scotland plc
Société Générale
Deutsche Bank AG New York Branch
Citicorp USA, Inc.
Barclays Bank plc
Bank One, N.A.
Sumitomo Mitsui Banking Corporation
BNP Paribas
Mizuho Corporate Bank, Ltd.
Morgan Stanley Bank
Bayerische Landesbank, Cayman Islands
Branch
Southwest Bank of Texas, N.A.
The Bank of Tokyo−Mitsubishi, Ltd.
BMO Nesbitt Burns Financing, Inc.
The Bank of New York
Wells Fargo Bank, N.A.
KBC Bank NV
Comerica Bank
Den Norske Bank ASA
Compass Bank
TOTAL
1
COMMITMENTS
21,000,000.00
18,000,000.00
18,000,000.00
18,000,000.00
18,000,000.00
18,000,000.00
18,000,000.00
18,000,000.00
18,000,000.00
15,000,000.00
15,000,000.00
10,000,000.00
10,000,000.00
10,000,000.00
10,000,000.00
10,000,000.00
10,000,000.00
10,000,000.00
10,000,000.00
10,000,000.00
10,000,000.00
5,000,000.00
300,000,000
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
SUBSIDIARIES
SCHEDULE 6.8
State or
Jurisdiction of
Organization
Delaware
Name
Noble Energy Marketing,
Inc.
Noble Gas Pipeline, Inc.
Delaware
Samedan Oil of Canada, Inc. Delaware
Delaware
Samedan North Sea, Inc.
Delaware
Samedan Oil of Indonesia,
Inc.
Samedan Pipe Line
Corporation
Samedan Royalty
Corporation
Comin 1989 Partnership
Delaware
Delaware
Oklahoma
Delaware
Delaware
Delaware
Samedan of Tunisia, Inc.
Samedan, Mediterranean
Sea, Inc.
Samedan of North Africa,
Inc.
Samedan Vietnam Limited
EDC Ireland
Samedan International
Noble Energy Hannah Ltd.
100% owned by Noble Energy, Inc.
Ownership %
100% owned by Noble Energy Marketing, Inc.
100% owned by Noble Energy, Inc.
100% owned by Noble Energy, Inc.
100% owned by Noble Energy, Inc.
100% owned by Noble Energy, Inc.
100% owned by Noble Energy, Inc.
52.267% general partnership interest owned by
Samedan Royalty Corporation
100% owned by Noble Energy, Inc.
100% owned by Noble Energy, Inc.
100% owned by Noble Energy, Inc.
Cayman Islands
Cayman Islands
Cayman Islands
Cayman Islands
100% owned by Samedan of North Africa, Inc.
100% owned by Samedan of North Africa, Inc.
100% owned by Samedan of North Africa, Inc.
100% owned by Samedan of North Africa, Inc.
1
Restricted/
Unrestricted
Subsidiary
Unrestricted
Unrestricted
Restricted
Restricted
Restricted
Restricted
Restricted
Restricted
Restricted
Unrestricted
Unrestricted
Unrestricted
Unrestricted
Unrestricted
Unrestricted
Name
Noble Energy West Africa
Ltd.
Machalapower Cia. Lpda.
Noble Energy Mediterranean
Ltd.
Samedan Transfer Sub
Temin 1987 Partnership
Energy Development
Corporation (Argentina), Inc.
Energy Development
Corporation (China), Inc.
Energy Development
Corporation (HIPS), Inc.
EDC Ecuador Ltd.
EDC Ecuador Limited
EDC Australia Ltd.
State or
Jurisdiction of
Organization
Ownership %
Restricted/
Unrestricted
Subsidiary
Delaware
100% owned by Samedan of North Africa, Inc.
Unrestricted
Cayman Islands
Cayman Islands
100% owned by Samedan International
100% owned by Samedan International
Cayman Islands
Oklahoma
Delaware
Delaware
Delaware
100% owned by Samedan International
50.35% general partnership interest owned by
Noble Energy, Inc. and 5.263% general partnership
interest owned by Samedan Royalty Corporation
100% owned by Noble Energy, Inc.
100% owned by Noble Energy, Inc.
100% owned by Noble Energy, Inc.
Delaware
Cayman Islands
Delaware
100% owned by Noble Energy, Inc.
100% owned by EDC Ecuador Ltd.
100% owned by Noble Energy, Inc.
Unrestricted
Unrestricted
Unrestricted
Restricted
Unrestricted
Unrestricted
Restricted
Unrestricted
Unrestricted
Restricted
2
Name
EDC Portugal Ltd.
Gasdel Pipeline System
Incorporated
Producers Service, Inc.
HGC, Inc.
EDC (UK) Limited
EDC Denmark, Inc.
EDC (Europe) Limited
EDC (ISE) Limited
EDC (Oilex) Limited
Brabant Oil Limited
LaTex Resources Inc.
State or
Jurisdiction of
Organization
Delaware
New Jersey
New Jersey
Delaware
Delaware
Delaware
England
Scotland
England
England
Colorado
Ownership %
100% owned by Noble Energy, Inc.
100% owned by Noble Energy, Inc.
100% owned by Noble Energy, Inc.
100% owned by Noble Energy, Inc.
100% owned by Noble Energy, Inc.
100% owned by EDC (UK) Limited
100% owned by EDC (UK) Limited
100% owned by EDC (Europe) Limited
100% owned by EDC (Europe) Limited
100% owned by EDC (Europe) Limited
100% owned by Noble Energy, Inc.
3
Restricted/
Unrestricted
Subsidiary
Restricted
Restricted
Restricted
Restricted
Restricted
Restricted
Restricted
Restricted
Restricted
Restricted
Unrestricted
SCHEDULE 7.2
EXISTING LIENS
NONE
1
BORROWING REQUEST
EXHIBIT 2.5
JPMorgan Chase Bank, as Administrative Agent
Agency Services
One Chase Manhattan Plaza, 8th Floor
New York, NY 10081
Attention: Muniram Appanna
Telephone No.: (212) 552−7943
Facsimile No.: (212) 552−3295
JPMorgan Chase Bank, as Administrative Agent
Global Oil & Gas Group
600 Travis, 20th Floor
Houston, Texas 77002
Attention: Peter Licalzi
Telephone: 713−216−8869
Facsimile: 713−216−4117
Gentlemen and Ladies:
NOBLE ENERGY, INC.
This Borrowing Request is delivered to you pursuant to Section 2.5 of the 364−Day Credit Agreement, dated as of October 30, 2003
(as may be amended, supplemented, restated or otherwise modified from time to time, the “Credit Agreement”), among Noble Energy,
Inc., a Delaware corporation (the “Borrower”), JPMorgan Chase Bank, as administrative agent (in such capacity, together with any
successor(s) thereto in such capacity, the “Agent”), the various other agents party thereto, and certain commercial lending institutions
as are or may become Lenders thereunder. Unless otherwise defined herein or the context otherwise requires, terms used herein have
the meanings provided in the Credit Agreement.
The Borrower hereby requests that a [Revolving] [Term] Loan be made in the aggregate principal amount of $ on ,
as a [Eurodollar Loan having an Interest Period of months] [Base Rate Loan].
The Borrower hereby acknowledges that, pursuant to Section 5.2.2 of the Credit Agreement, each of the delivery of this
Borrowing Request and the acceptance by the Borrower of the proceeds of the Loans requested hereby constitute a representation and
warranty by the Borrower that, on the date of such Loans, and before and after giving effect thereto and to the application of the
proceeds therefrom, all statements set forth in Section 5.2.1 are true and correct in all material respects.
2
The Borrower agrees that if prior to the time of the Borrowing requested hereby any matter certified to herein by it will not be true and
correct at such time as if then made, it will immediately so notify the Agent. Except to the extent, if any, that prior to the time of the
Borrowing requested hereby the Agent shall receive written notice to the contrary from the Borrower, each matter certified to herein
shall be deemed once again to be certified as true and correct at the date of such Borrowing as if then made.
Please wire transfer the proceeds of the Borrowing to the accounts of the following persons at the financial institutions indicated
respectively:
Amount to be Transferred
Person to be Paid
Name
Account No.
Name, Address, etc.
of Transferee Lender
$
$
Balance of such proceeds
The Borrower
Attention:
Attention:
Attention:
The Borrower has caused this Borrowing Request to be executed and delivered, and the certification and warranties contained herein
to be made, by its duly Authorized Officer this day of , 200 .
NOBLE ENERGY, INC.
By
Name:
Title:
3
CONTINUATION/CONVERSION NOTICE
EXHIBIT 2.6
JPMorgan Chase Bank, as Administrative Agent
Agency Services
One Chase Manhattan Plaza, 8th Floor
New York, NY 10081
Attention: Muniram Appanna
Telephone No.: (212) 552−7943
Facsimile No.: (212) 552−3295
JPMorgan Chase Bank, as Administrative Agent
Global Oil & Gas Group
600 Travis, 20th Floor
Houston, Texas 77002
Attention: Peter Licalzi
Telephone: 713−216−8869
Facsimile: 713−216−4117
Gentlemen and Ladies:
NOBLE ENERGY, INC.
This Continuation/Conversion Notice is delivered to you pursuant to Section 2.6 of the 364−Day Credit Agreement, dated as of
October 30, 2003 (as may be amended, supplemented, restated or otherwise modified from time to time, the “Credit Agreement”),
among Noble Energy, Inc., a Delaware corporation (the “Borrower”), JPMorgan Chase Bank, as administrative agent (in such
capacity, together with any successor(s) thereto in such capacity, the “Agent”), the other agents party thereto, and certain commercial
lending institutions as are or may become Lenders thereunder. Unless otherwise defined herein or the context otherwise requires,
terms used herein have the meanings provided in the Credit Agreement.
The Borrower hereby requests that on , 200 ,
(1) $ of the presently outstanding principal amount of the [Revolving] [Term] Loans originally made on ,
200 [and $ of the presently outstanding principal amount of the [Revolving] [Term] Loans originally made on
, 200 ],
(2) and all presently being maintained as [Base Rate Loans] [Eurodollar Loans] [Term Loans],
(3) be [converted into] [continued as],
1
(4) [Eurodollar Loans having an Interest Period of months] [Base Rate Loans].
The Borrower hereby:
(a) certifies and warrants that no Default or Event of Default has occurred and is continuing; and
(b) agrees that if prior to the time of such continuation or conversion any matter certified to herein by it will not be true and
correct at such time as if then made, it will immediately so notify the Agent.
Except to the extent, if any, that prior to the time of the continuation or conversion requested hereby the Agent shall receive written
notice to the contrary from the Borrower, each matter certified to herein shall be deemed to be certified at the date of such
continuation or conversion as if then made.
The Borrower has caused this Continuation/Conversion Notice to be executed and delivered, and the certification and warranties
contained herein to be made, by its Authorized Officer this day of , 200 .
NOBLE ENERGY, INC.
By
Name:
Title:
2
[FORM OF]
NOTE
EXHIBIT 2.8
$
October 30, 2003
FOR VALUE RECEIVED, the undersigned, NOBLE ENERGY, INC., a Delaware corporation (the “Borrower”), promises to pay to
the order of (the “Lender”) on the Maturity Date the principal sum of AND
/100 DOLLARS ($ ) or, if less, the aggregate unpaid principal amount of all Obligations shown on the schedule
attached hereto (and any continuation thereof, provided, however, that the failure to make such notations shall not limit or otherwise
affect the obligations of the Borrower under this Note or the Credit Agreement), in either case made by the Lender pursuant to that
certain 364−Day Credit Agreement, dated as of October 30, 2003 (together with all amendments and other modifications, if any, from
time to time thereafter made thereto, the “Credit Agreement”), among Borrower, the Lenders party thereto (including the Lender),
JPMorgan Chase Bank, as administrative agent (in such capacity, together with any successor(s) thereto in such capacity, the
“Agent”), and the other agents party thereto.
The Borrower also promises to pay interest on the unpaid principal amount hereof from time to time outstanding from the date hereof
until maturity (whether by acceleration or otherwise) and, after maturity, until paid, at the rates per annum and on the dates specified
in the Credit Agreement.
This Note (the “Note”) evidences Indebtedness incurred under the Credit Agreement to which reference is made for a statement of the
terms and conditions on which the Borrower is permitted and required to make prepayments and repayments of principal of the
Indebtedness evidenced by this Note and on which such Indebtedness may be declared to be immediately due and payable. Capitalized
terms used herein and not otherwise defined herein shall have the meanings assigned to such terms in the Credit Agreement.
All parties hereto, whether as makers, endorsers, or otherwise, severally waive presentment for payment, demand, protest and notice
of dishonor.
THIS NOTE SHALL BE CONSTRUED IN ACCORDANCE WITH AND GOVERNED BY THE LAWS OF THE STATE OF
TEXAS.
NOBLE ENERGY, INC.
By:
Name:
Title:
1
LOANS AND PRINCIPAL PAYMENTS
Date
Amount of
Loan Made
Interest
Period (if
Applicable)
Amount of
Principal
Repaid
Unpaid
Principal
Balance
Total
Notation
Made By
2
[Opinion of Counsel to the Borrower]
[TO BE ATTACHED AND
BE IN SUBSTANTIALLY THE SAME FORM AS NOVEMBER, 2002 LEGAL OPINION]
1
EXHIBIT 5.1.3
LENDER ASSIGNMENT AGREEMENT
EXHIBIT 10.10
To: Noble Energy, Inc.,
as the Borrower
To: JPMorgan Chase Bank,
as Administrative Agent
Gentlemen and Ladies:
NOBLE ENERGY, INC.
We refer to Section 10.10.1 of the 364−Day Credit Agreement, dated as of October 30, 2003 (as may be amended, supplemented,
restated or otherwise modified from time to time, the “Credit Agreement”), among Noble Energy, Inc., a Delaware corporation (the
“Borrower”), JPMorgan Chase Bank, as administrative agent (in such capacity, together with any successor(s) thereto in such
capacity, the “Agent”), the other agents party thereto, and certain commercial lending institutions as are or may become Lenders
thereunder. Unless otherwise defined herein or the context otherwise requires, terms used herein have the meanings provided in the
Credit Agreement.
This agreement is delivered to you pursuant to Section 10.10.1 of the Credit Agreement and also constitutes notice to each of you,
pursuant to Section 10.10.1 of the Credit Agreement, of the assignment and delegation to (the “Assignee”) of %
of the Loans and Commitments of (the “Assignor”) outstanding under the Credit Agreement on the date hereof. After
giving effect to the foregoing assignment and delegation, the Assignor’s and the Assignee’s Percentages for the purposes of the Credit
Agreement are set forth opposite such Person’s name on the signature pages hereof.
[Add paragraph dealing with accrued interest and fees with respect to Loans assigned, if applicable.]
The Assignee hereby acknowledges and confirms that it has received a copy of the Credit Agreement and the exhibits related thereto,
together with copies of the documents which were required to be delivered under the Credit Agreement as a condition to the making of
the Loans thereunder. The Assignee further confirms and agrees that in becoming a Lender and in making its Commitments and
Loans under the Credit Agreement, such actions have and will be made without recourse to, or representation or warranty by the
Agent.
Except as otherwise provided in the Credit Agreement, effective as of the date of acceptance hereof by the Agent
(a) the Assignee (i) shall be deemed automatically to have become a party to the Credit Agreement, have all the rights and
obligations of a “Lender” under the Credit Agreement and the other Loan Documents as if it were an original signatory thereto to the
extent specified in the second paragraph hereof; and (ii) agrees to be bound by the terms and conditions set forth in
1
the Credit Agreement and the other Loan Documents as if it were an original signatory thereto; and
(b) the Assignor shall be released from its obligations under the Credit Agreement and the other Loan Documents to the extent
specified in the second paragraph hereof.
The Assignor and the Assignee hereby agree that the [Assignor] [Assignee] will pay to the Agent the processing fee referred to in
Section 10.10.1 of the Credit Agreement upon the delivery hereof.
The Assignee hereby advises each of you of the following administrative details with respect to the assigned Loans and Commitments
and requests the Agent to acknowledge receipt of this document:
(A) Address for Notices:
Institution Name:
Attention:
Domestic Office:
Telephone:
Facsimile:
Telex (Answerback):
LIBOR Office:
Telephone:
Facsimile:
Telex (Answerback):
(B) Payment Instructions:
The Assignee agrees to furnish to the Agent (i) the tax form required by Section 4.6 (if so required) of the Credit Agreement no later
than the date of acceptance hereof by the Agent and (ii) if the Assignee is not already a Lender under the Credit Agreement, an
Administrative Questionnaire in the form supplied by the Agent, duly completed by the Assignee.
This Agreement may be executed by the Assignor and Assignee in separate counterparts, each of which when so executed and
delivered shall be deemed to be an original and all of which taken together shall constitute one and the same agreement.
2
Adjusted Percentage
[ASSIGNOR]
By:
Name:
Title:
By:
Name:
Title:
[ASSIGNEE]
Commitment and Loans: %
Percentage
Commitment and Loans: %
Accepted and Acknowledged this day of , 200 ,
JPMORGAN CHASE BANK,
as Administrative Agent
By:
Name:
Title:
3
ARTICLE I
SECTION 1.1
SECTION 1.2
SECTION 1.3
SECTION 1.4
ARTICLE II
SECTION 2.1
SECTION 2.2
SECTION 2.3
SECTION 2.4
SECTION 2.5
SECTION 2.6
SECTION 2.7
SECTION 2.8
ARTICLE III
SECTION 3.1
SECTION 3.2
SECTION 3.3
ARTICLE IV
SECTION 4.1
SECTION 4.2
SECTION 4.3
SECTION 4.4
SECTION 4.5
SECTION 4.6
SECTION 4.7
SECTION 4.8
SECTION 4.9
SECTION 4.10
TABLE OF CONTENTS
DEFINITIONS AND ACCOUNTING TERMS
Defined Terms
Use of Defined Terms
Cross−References
Accounting and Financial Determinations
THE FACILITY AND BORROWING PROCEDURES
Facility
[Intentionally Omitted]
Reduction of Commitment Amount
Base Rate Loans and Eurodollar Loans
Borrowing Procedures for Loans
Continuation and Conversion Elections
Funding
Repayment of Loans; Evidence of Debt
REPAYMENTS, PREPAYMENTS, INTEREST AND FEES
Repayments and Prepayments
Interest Provisions
Fees
CERTAIN EURODOLLAR AND OTHER PROVISIONS
Eurodollar Lending Unlawful
Deposits Unavailable or Eurodollar Interest Rate Unascertainable
Increased Eurodollar Borrowing Costs, etc
Funding Losses
Increased Capital Costs
Taxes
Special Fees in Respect of Reserve Requirements
Payments, Computations, etc
Sharing of Payments
Replacement of Lender on Account of Increased Costs, Eurodollar Lending Unlawful,
Reserve Requirements, Taxes, Certain Dissents, etc
i
SECTION 4.11
ARTICLE V
SECTION 5.1
SECTION 5.2
ARTICLE VI
SECTION 6.1
SECTION 6.2
SECTION 6.3
SECTION 6.4
SECTION 6.5
SECTION 6.6
SECTION 6.7
SECTION 6.8
SECTION 6.9
SECTION 6.10
SECTION 6.11
SECTION 6.12
SECTION 6.13
SECTION 6.14
ARTICLE VII
SECTION 7.1
SECTION 7.2
ARTICLE VIII
SECTION 8.1
SECTION 8.2
SECTION 8.3
ARTICLE IX
SECTION 9.1
SECTION 9.2
SECTION 9.3
SECTION 9.4
Maximum Interest
CONDITIONS
Effective Date
All Borrowings
REPRESENTATIONS AND WARRANTIES
Organization, etc
Due Authorization, Non−Contravention, etc
Government Approval, Regulation, etc
Validity, etc
Financial Information
No Material Adverse Change
Litigation, Labor Controversies, etc
Subsidiaries
Taxes
Pension and Welfare Plans
Environmental Warranties and Compliance
Regulation U
Accuracy of Information
Use of Proceeds
COVENANTS
Affirmative Covenants
Negative Covenants
EVENTS OF DEFAULT
Listing of Events of Default
Action if Bankruptcy
Action if Other Event of Default
THE AGENTS
Actions
Funding Reliance, etc
Exculpation
Successor
ii
SECTION 9.5
SECTION 9.6
SECTION 9.7
ARTICLE X
SECTION 10.1
SECTION 10.2
SECTION 10.3
SECTION 10.4
SECTION 10.5
SECTION 10.6
SECTION 10.7
SECTION 10.8
SECTION 10.9
SECTION 10.10
SECTION 10.11
SECTION 10.12
SECTION 10.13
SECTION 10.14
SECTION 10.15
Loans by the Agents
Credit Decisions
Copies, etc
MISCELLANEOUS PROVISIONS
Waivers, Amendments, etc
Notices
Payment of Costs, Expenses and Taxes
Indemnification
Survival
Severability
Headings
Governing Law; Entire Agreement
Successors and Assigns
Sale and Transfer of Loans and Commitments; Participations in Loans and Commitments
Other Transactions
Confidentiality
Forum Selection and Consent to Jurisdiction
Waiver of Jury Trial
NO ORAL AGREEMENTS
iii
SCHEDULE I
SCHEDULE II
SCHEDULE 6.8
SCHEDULE 7.2
EXHIBIT 2.5
EXHIBIT 2.6
EXHIBIT 2.8
EXHIBIT 5.1.3
EXHIBIT 10.10
SCHEDULES AND EXHIBITS
−
−
−
−
−
−
−
−
−
Disclosure Schedule
Schedule of Commitments
Subsidiaries
Existing Liens
Form of Borrowing Request
Form of Continuation/Conversion Notice
Form of Note
Form of Opinion of Counsel
Form of Lender Assignment Agreement
iv
NOBLE ENERGY, INC.
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(in thousands)
Exhibit 12.1
2003
2002
Year ended December 31,
2001
2000
1999
Income from continuing operations
before cumulative effect of change in
accounting principle
Add (deduct):
Fixed charges
Interest capitalized
Distributions less equity in earnings of
equity investees
Earnings as defined
Interest expense, excluding capitalized
interest
Interest capitalized
Interest portion of rental expense
Fixed charges as defined
Ratio of earnings to fixed charges
$
141,639
$
27,896
$
150,130
$
207,890
$
43,043
62,075
(14,134)
5,499
195,079
46,977
14,134
964
62,075
3.14
$
$
$
64,566
(16,331)
8,164
84,295
47,709
16,331
526
64,566
1.31
$
$
$
54,434
(15,953)
(6,981)
181,630
38,007
15,953
474
54,434
3.34
$
$
$
50,434
(6,326)
(13,544)
238,454
43,697
6,326
411
50,434
4.73
$
$
$
$
$
$
49,393
(5,894)
—
86,542
43,041
5,894
458
49,393
1.75
NAME
LaTex Resources Inc.
Noble Energy Marketing, Inc.
Noble Gas Pipeline, Inc.
Samedan of North Africa, Inc.
Noble Energy West Africa Ltd.
Noble Energy Hannah Ltd.
EDC Ireland
Samedan International
Noble Energy EG Ltd.
Alba Associates LLC
Alba Plant LLC
Machalapower Cia. Ltda.
Noble Energy Mediterranean Ltd.
Yam Tethys Ltd.
Samedan Transfer Sub
AMPCO Marketing, L.L.C.
AMPCO Services, L.L.C.
Samedan Vietnam Limited
Atlantic Methanol Capital Company
Samedan Methanol
Atlantic Methanol Associates LLC
Atlantic Methanol Production Company LLC
Samedan, Mediterranean Sea, Inc.
Samedan North Sea, Inc.
Samedan Oil of Canada, Inc.
Samedan Oil of Indonesia, Inc.
SUBSIDIARIES
STATE OF JURISDICTION OF
ORGANIZATION
Colorado
Delaware
Delaware
Delaware
Delaware
Cayman Islands
Cayman Islands
Cayman Islands
Cayman Islands
Cayman Islands
Cayman Islands
Cayman Islands
Cayman Islands
Israel
Cayman Islands
Michigan
Michigan
Cayman Islands
Cayman Islands
Cayman Islands
Cayman Islands
Cayman Islands
Delaware
Delaware
Delaware
Delaware
EXHIBIT 21
TO FORM 10−K
REF
(1)
(1)
(2)
(1)
(3)
(3)
(3)
(3)
(4)
(9)
(10)
(4)
(4)
(14)
(4)
(5)
(5)
(3)
(5)
(6)
(7)
(8)
(1)
(1)
(1)
(1)
Samedan Pipe Line Corporation
Samedan Royalty Corporation
Samedan of Tunisia, Inc.
Noble Energy (Louisiana), LLC
Noble Energy, LLC
Noble Energy, LP
EDC Australia Ltd.
EDC Ecuador Ltd.
Noble Energy Ecuador Ltd.
EDC Portugal Ltd.
Energy Development Corporation (Argentina), Inc.
Energy Development Corporation (China), Inc.
Energy Development Corporation (HIPS), Inc.
Gasdel Pipeline System Incorporated
HGC, Inc.
Producers Service, Inc.
EDC (UK) Limited
EDC (Denmark) Inc.
Noble Energy (Europe) Limited
Noble Energy (ISE) Limited
Noble Energy (Oilex) Limited
Brabant Oil Limited
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Cayman Islands
Delaware
Delaware
Delaware
Delaware
New Jersey
Delaware
New Jersey
Delaware
Delaware
United Kingdom
United Kingdom
United Kingdom
United Kingdom
(1)
(1)
(1)
(1)
(1)
(15)
(1)
(1)
(13)
(1)
(1)
(1)
(1)
(1)
(1)
(1)
(1)
(11)
(11)
(12)
(12)
(12)
REFERENCES:
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(10)
(11)
(12)
(13)
(14)
(15)
100% directly owned by Noble Energy, Inc. (Registrant)
100% directly owned by Noble Energy Marketing, Inc.
100% directly owned by Samedan of North Africa, Inc.
100% directly owned by Samedan International
50% directly owned by Samedan of North Africa, Inc.
100% directly owned by Atlantic Methanol Capital Company
50% directly owned by Samedan Methanol
90% directly owned by Atlantic Methanol Associates LLC
35% directly owned by Samedan International
80% directly owned by Alba Associates LLC
100% directly owned by EDC (UK) Limited
100% directly owned by Noble Energy (Europe) Limited
100% directly owned by EDC Ecuador Ltd.
47.059% directly owned by Noble Energy Mediterranean Ltd.
1% General Partnership Interest by Noble Energy, Inc. (Registrant); 99% Limited Partnership Interest by Noble
Energy, LLC
INDEPENDENT AUDITORS’ CONSENT
EXHIBIT 23.1
To the Shareholders and Board of Directors of Noble Energy, Inc.:
We consent to the incorporation by reference in the registration statements (File Nos. 333−18929 and 333−82953) on Form S−3 and
the registration statements (File Nos. 333−108162, 333−39299, 33−32692, 2−66654 and 33−54084) on Form S−8 of Noble Energy,
Inc. of our report dated February 26, 2004 with respect to the consolidated balance sheets of Noble Energy, Inc. as of December 31,
2003 and 2002 and the related consolidated statements of operations, shareholders’ equity and other comprehensive income, and cash
flows for each of the years in the three−year period ended December 31, 2003, and the related financial statement schedule, which
report appears in the Form 10−K of Noble Energy, Inc.
As discussed in Note 1 to the consolidated financial statements, effective January 1, 2003, the Company changed its method of
accounting for asset retirement obligations.
KPMG LLP
Houston, Texas
March 10, 2004
Consent of Independent Auditors
Exhibit 23.2
We consent to the incorporation by reference in the Registration Statements (Form S−3 Nos. 333−82953 and 333−18929, Form S−8
Nos. 333−108162, 333−39299, 33−54084, 33−32692 and 2−66654) of Noble Energy, Inc. of our report dated January 28, 2004, with respect to the
financial statements of Atlantic Methanol Production Company, LLC included in this Annual Report (Form 10−K) for the year ended December 31, 2003.
Ernst & Young LLP
March 10, 2004
Fort Worth, Texas
EXHIBIT 31.1
CERTIFICATION
I, Charles D. Davidson, certify that:
1.
I have reviewed this annual report on Form 10−K of Noble Energy, Inc.;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
2.
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 report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly
3.
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 report;
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls
4.
and procedures (as defined in Exchange Act Rules 13a−15(e) and 15d−15(e)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our
supervision, 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 report is being prepared;
b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about
the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;
and
c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s
most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant’s internal control over financial reporting;
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal
5.
control over financial reporting, 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 and material weaknesses in the design or operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s
internal control over financial reporting.
Date: March 12, 2004
/s/ CHARLES D. DAVIDSON
CHARLES D. DAVIDSON
Chief Executive Officer
1
EXHIBIT 31.2
CERTIFICATION
I, James L. McElvany, certify that:
1.
I have reviewed this annual report on Form 10−K of Noble Energy, Inc.;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
2.
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 report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly
3.
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 report;
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls
4.
and procedures (as defined in Exchange Act Rules 13a−15(e) and 15d−15(e)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our
supervision, 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 report is being prepared;
b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about
the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;
and
c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s
most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant’s internal control over financial reporting;
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal
5.
control over financial reporting, 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 and material weaknesses in the design or operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s
internal control over financial reporting.
Date: March 12, 2004
/s/ JAMES L. McELVANY
JAMES L. McELVANY
Chief Financial Officer
1
CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES−OXLEY ACT OF 2002
(18 U.S.C. SECTION 1350)
EXHIBIT 32.1
In connection with the accompanying Annual Report of Noble Energy, Inc. (the “Company”) on Form 10−K for the period ended
December 31, 2003 (the “Report”), I, Charles D. Davidson, Chief Executive Officer of the Company, hereby certify that to my
knowledge:
(1)
U.S.C. 78m or 78o(d)); and
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15
(2)
operations of the Company.
The information contained in the Report fairly presents, in all material respects, the financial condition and results of
Date: March 12, 2004
/s/ CHARLES D. DAVIDSON
CHARLES D. DAVIDSON
Chief Executive Officer
CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES−OXLEY ACT OF 2002
(18 U.S.C. SECTION 1350)
EXHIBIT 32.2
In connection with the accompanying Annual Report of Noble Energy, Inc. (the “Company”) on Form 10−K for the period ended
December 31, 2003 (the “Report”), I, James L. McElvany, Chief Financial Officer of the Company, hereby certify that to my
knowledge:
(1)
U.S.C. 78m or 78o(d)); and
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15
(2)
operations of the Company.
The information contained in the Report fairly presents, in all material respects, the financial condition and results of
Date: March 12, 2004
/s/ JAMES L. McELVANY
JAMES L. McELVANY
Chief Financial Officer
_______________________________________________
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