UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

 


 

FORM 10-K

 

 

 

(Mark One)

 

 

ý

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

 

 

 

o

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

 

73-0785597

(State of incorporation)

 

(I.R.S. employer identification number)

 

 

 

100 Glenborough Drive, Suite 100
Houston, Texas

 

77067

(Address of principal executive offices)

 

(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

 

Name of Each Exchange on
Which Registered

 

 

 

Common Stock, $3.33-1/3 par value
Preferred Stock Purchase Rights

 

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  ý   No  o

 

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.  ý

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes  ý   No  o

 

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

 

 

PART IV.

 

Item 15.

 

Exhibits, Financial Statement Schedules and Reports on Form 8-K

 

 

ii



 

PART I

 

Item 1.            Business.

 

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

Barrel

Bbls

Barrels

MBbls

Thousand barrels

Bpd

Barrels per day

Bopd

Barrels oil per day

MMBbl

Million barrels

MBpd

Thousand barrels per day

MMBpd

Million barrels per day

MBopd

Thousand barrels oil per day

MMBopd

Million barrels oil per day

BOE

Barrels oil equivalent

MMBoe

Million barrels oil equivalent

MMBoepd

Million barrels oil equivalent per day

$MM

Millions of dollars

Kwh

Kilowatt hour

MW

Megawatt

MWH

Megawatt hours

Mcf

Thousand cubic feet

Mcfpd

Thousand cubic feet per day

Mcfe

Thousand cubic feet equivalent

MMcf

Million cubic feet

MMcfepd

Million cubic feet equivalent per day

MMcfpd

Million cubic feet per day

Bcf

Billion cubic feet

Bcfe

Billion cubic feet equivalent

Bcfepd

Billion cubic feet equivalent per day

Bcfpd

Billion cubic feet per day

BTU

British thermal unit

BTUpcf

British thermal unit per cubic foot

MMBTU

Million British thermal unit

MMBTUpd

Million British thermal unit per day

MTpd

Metric tons per day

LPG

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:

 

 

 

2003

 

2002

 

2001

 

(in percentages)

 

Oil

 

Gas

 

Oil

 

Gas

 

Oil

 

Gas

 

Operated well count basis

 

19.6

 

60.1

 

23.3

 

62.8

 

24.8

 

60.6

 

Operated sales volume basis

 

33.3

 

48.8

 

29.3

 

45.1

 

37.2

 

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:

 

 

 

2003

 

2002

 

2001

 

(in percentages)

 

Oil

 

Gas

 

Oil

 

Gas

 

Oil

 

Gas

 

Non-operated well count basis

 

80.4

 

39.9

 

76.7

 

37.2

 

75.2

 

39.4

 

Non-operated sales volume basis

 

66.7

 

51.2

 

70.7

 

54.9

 

62.8

 

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:

 

 

 

2003

 

2002

 

2001

 

Crude oil production (MMBbl)

 

13.1

 

10.6

 

9.1

 

Natural gas production (Bcf)

 

122.9

 

124.5

 

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:

 

 

 

2003

 

2002

 

2001

 

Total crude oil equivalents (MMBoe)

 

33.6

 

31.4

 

30.8

 

Total natural gas equivalents (Bcfe)

 

201.7

 

188.2

 

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.

 

 

 

Net Exploratory Wells

 

Net Development Wells

 

 

 

Productive(1)

 

Dry(2)

 

Productive(1)

 

Dry(2)

 

Year Ended
December 31,

 

U.S.

 

Int’l

 

U.S.

 

Int’l

 

U.S.

 

Int’l

 

U.S.

 

Int’l

 

2003

 

10.84

 

.07

 

12.40

 

2.67

 

25.10

 

7.32

 

8.16

 

 

 

2002

 

9.78

 

 

 

11.45

 

3.27

 

41.53

 

12.84

 

11.17

 

 

 

2001

 

4.87

 

.63

 

10.79

 

5.41

 

68.30

 

13.67

 

12.88

 

1.62

 

 


(1)          A productive well is an exploratory or a development well that is not a dry hole.

 

(2)          A dry hole is an exploratory or development well determined to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion as an oil or gas well.

 

At January 31, 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:

 

 

 

2003(1)(2)

 

2002(1)(2)

 

2001(1)(2)

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Crude Oil Wells

 

 

 

 

 

 

 

 

 

 

 

 

 

United States – Onshore

 

196.0

 

118.2

 

1,131.0

 

458.7

 

1,364.5

 

573.6

 

United States – Offshore

 

186.0

 

114.2

 

232.5

 

95.7

 

212.5

 

120.0

 

International

 

716.0

 

88.8

 

687.0

 

81.3

 

670.0

 

75.7

 

Total

 

1,098.0

 

321.2

 

2,050.5

 

635.7

 

2,247.0

 

769.3

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas Wells

 

 

 

 

 

 

 

 

 

 

 

 

 

United States – Onshore

 

1,645.0

 

1,042.1

 

1,603.0

 

1,006.6

 

1,673.5

 

1,025.7

 

United States – Offshore

 

299.0

 

116.5

 

265.5

 

184.9

 

333.5

 

143.3

 

International

 

34.0

 

8.4

 

42.0

 

13.1

 

38.0

 

8.4

 

Total

 

1,978.0

 

1,167.0

 

1,910.5

 

1,204.6

 

2,045.0

 

1,177.4

 

 


(1)          Productive wells are producing wells and wells capable of production. A gross well is a well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.

 

(2)          One or more completions in the same borehole are counted as one well in this table.

 

The following table summarizes multiple completions and non-producing wells as of December 31 for the years shown. Included in wells not producing are productive wells awaiting additional action, pipeline connections or shut-in for various reasons.

 

 

 

2003

 

2002

 

2001

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Multiple Completions

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil

 

9.0

 

5.8

 

12.0

 

6.0

 

13.5

 

6.9

 

Natural Gas

 

29.0

 

11.3

 

28.5

 

8.9

 

36.5

 

14.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Not Producing (Shut-in)

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil

 

573.0

 

109.2

 

565.0

 

212.3

 

391.0

 

179.2

 

Natural Gas

 

337.0

 

142.5

 

121.0

 

73.0

 

100.0

 

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.

 

 

 

Year Ended December 31,

 

 

 

2003

 

2002(6)

 

2001(6)

 

Average sales price per Bbl of crude oil (1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

$

26.21

 

$

23.29

 

$

23.02

 

International

 

$

28.94

 

$

24.98

 

$

23.98

 

 

 

 

 

 

 

 

 

Combined (2)

 

$

27.72

 

$

24.22

 

$

23.49

 

 

 

 

 

 

 

 

 

Average sales price per Mcf of natural gas (1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

$

4.75

 

$

3.24

 

$

4.21

 

International (3)

 

$

1.17

 

$

1.18

 

$

1.60

 

 

 

 

 

 

 

 

 

Combined (4)

 

$

4.13

 

$

2.89

 

$

3.86

 

 

 

 

 

 

 

 

 

Average production cost per Mcfe (5):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

$

.74

 

$

.63

 

$

.61

 

International

 

$

.78

 

$

.43

 

$

.39

 

 

 

 

 

 

 

 

 

Combined

 

$

.75

 

$

.57

 

$

.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

 

Working
Interest (%)

 

 

 

 

 

East Breaks

 

 

 

279

*

 

33

 

 

464

*

 

48

 

 

465

*

 

48

 

 

475

*

 

100

 

 

510

*

 

33

 

 

519

*

 

100

 

 

563

*

 

100

 

 

 

 

 

 

 

 

Green Canyon

 

 

 

 

23

 

 

100

 

 

85

*

 

50

 

 

142

 

 

100

 

 

185

*

 

100

 

 

186

*

 

100

 

 

187

*

 

100

 

 

199

*

 

20

 

 

228

*

 

100

 

 

303

*

 

40

 

 

507

*

 

50

 

 

723

*

 

100

 

 

724

*

 

100

 

 

768

*

 

100

 

 

955

*

 

7

 

 

958

*

 

25

 

 

 

 

 

 

 

 

West Cameron

 

 

 

 

136

 

 

40

 

 

311

 

 

10

 

 

392

 

 

100

 

 

393

 

 

100

 

 

400

 

 

100

 

 

419

 

 

100

 

 

422

 

 

50

 

 

423

 

 

100

 

 

438

 

 

100

 

 

443

 

 

100

 

 

446

 

 

100

 

 

 

 

 

 

 

 

Mustang Island

 

 

 

 

829

 

 

80

 

 

830

 

 

80

 

 

831

 

 

100

 

 

 

 

 

 

 

 

Vermilion

 

 

 

 

208

 

 

25

 

 

227

 

 

100

 

 

228

 

 

100

 

 

230

 

 

100

 

 

232

 

 

50

 

 

235

 

 

100

 

 

352

 

 

100

 

 

353

 

 

100

 

 

391

 

 

100

 

 

 

 

 

 

 

 

Garden Banks

 

 

 

 

25

 

 

50

 

 

416

*

 

100

 

 

460

*

 

100

 

 

461

*

 

100

 

 

751

*

 

100

 

 

795

*

 

100

 

 

841

*

 

39

 

 

 

 

 

 

 

 

Main Pass

 

 

 

 

107

 

 

25

 

 

109

 

 

25

 

 

110

 

 

25

 

 

192

 

 

100

 

 

 

 

 

 

 

 

East Cameron

 

 

 

 

342

 

 

67

 

 

348

 

 

30

 

 

355

 

 

100

 

 

 

 

 

 

 

 

South Timbalier

 

 

 

 

62

 

 

100

 

 

278

 

 

50

 

 

 

 

 

 

 

 

Ship Shoal

 

 

 

 

73

 

 

50

 

 

 

 

 

 

 

 

Galveston

 

 

 

 

249-L

 

 

50

 

 

 

 

 

 

 

 

South Marsh Island

 

 

 

 

38

 

 

100

 

 

64

 

 

67

 

 

70

 

 

50

 

 

145

 

 

100

 

 

195

 

 

50

 

 

 

 

 

 

 

 

Mississippi Canyon

 

 

 

 

26

*

 

75

 

 

70

*

 

75

 

 

71

*

 

75

 

 

115

*

 

75

 

 

116

*

 

100

 

 

123

*

 

75

 

 

159

*

 

75

 

 

204

*

 

100

 

 

524

*

 

50

 

 

595

*

 

24

 

 

602

*

 

75

 

 

639

*

 

24

 

 

665

*

 

50

 

 

769

*

 

100

 

 

811

*

 

30

 

 

849

*

 

34

 

 

855

*

 

30

 

 

856

*

 

30

 

 

857

*

 

30

 

 

892

*

 

35

 

 

896

*

 

67

 

 

900

*

 

30

 

 

901

*

 

30

 

 

911

*

 

40

 

 

999

*

 

30

 

 

1000

*

 

30

 

 

 

 

 

 

 

 

Brazos

 

 

 

 

308-L

 

 

50

 

 

543

 

 

100

 

 

 

 

 

 

 

 

Ewing Bank

 

 

 

 

834

 

 

14

 

 

949

 

 

52

 

 

993

 

 

98

 

 

 

 

 

 

 

 

Eugene Island

 

 

 

 

35

 

 

25

 

 

36

 

 

25

 

 

37

 

 

25

 

 

38

 

 

25

 

 

96

 

 

25

 

 

317

 

 

67

 

 

 

 

 

 

 

 

High Island

 

 

 

 

A-218

 

 

100

 

 

A-230

 

 

100

 

 

A-232

 

 

50

 

 

A-422

 

 

100

 

 

A-516

 

 

100

 

 

A-587

 

 

3

 

 

 

 

 

 

 

 

Viosca Knoll

 

 

 

 

23

 

 

100

 

 

157

 

 

100

 

 

697

 

 

50

 

 

908

*

 

100

 

 

917

*

 

10

 

 

961

*

 

10

 

 

962

*

 

10

 

 

 

 

 

 

 

 

Atwater Valley

 

 

 

 

10

*

 

100

 

 

11

*

 

100

 

 

23

*

 

100

 

 

66

*

 

100

 

 

67

*

 

100

 

 

327

*

 

79

 

 

533

*

 

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:

 

 

 

Developed Acreage (1)(2)

 

Undeveloped Acreage (2)(3)(4)

 

Location

 

Gross Acres

 

Net Acres

 

Gross Acres

 

Net Acres

 

United States Onshore

 

 

 

 

 

 

 

 

 

Alabama

 

 

 

 

 

2,926

 

505

 

California

 

2,368

 

1,191

 

5,914

 

2,610

 

Colorado

 

79,251

 

60,372

 

27,636

 

20,817

 

Kansas

 

93,278

 

52,833

 

18,724

 

12,828

 

Louisiana

 

33,712

 

11,398

 

36,920

 

11,465

 

Michigan

 

 

 

 

 

1,876

 

427

 

Mississippi

 

878

 

34

 

1,884

 

51

 

Montana

 

201,622

 

122,928

 

4,598

 

1,612

 

Nevada

 

 

 

 

 

50,996

 

49,727

 

New Mexico

 

2,117

 

826

 

2,480

 

1,833

 

North Dakota

 

 

 

 

 

685

 

314

 

Oklahoma

 

137,943

 

48,756

 

12,752

 

5,833

 

Texas

 

88,076

 

33,952

 

114,190

 

46,331

 

Utah

 

1,280

 

260

 

3,232

 

2,456

 

Wyoming

 

27,183

 

11,834

 

66,388

 

35,973

 

Total United States Onshore

 

667,708

 

344,384

 

351,201

 

192,782

 

United States Offshore (Federal Waters)

 

 

 

 

 

 

 

 

 

Alabama

 

97,920

 

37,670

 

24,381

 

14,467

 

California

 

38,833

 

12,039

 

52,364

 

9,422

 

Louisiana

 

543,986

 

239,863

 

443,042

 

285,774

 

Mississippi

 

37,756

 

19,260

 

120,960

 

58,070

 

Texas

 

214,325

 

97,702

 

114,911

 

76,625

 

Total United States Offshore (Federal Waters)

 

932,820

 

406,534

 

755,658

 

444,358

 

International

 

 

 

 

 

 

 

 

 

Argentina

 

28,988

 

3,977

 

2,426,221

 

2,353,455

 

China

 

7,413

 

4,225

 

1,617,549

 

808,775

 

Denmark

 

 

 

 

 

81,050

 

32,420

 

Ecuador

 

12,355

 

12,355

 

851,771

 

851,771

 

Equatorial Guinea

 

45,203

 

15,727

 

266,754

 

92,808

 

Israel

 

123,552

 

58,142

 

292,572

 

137,681

 

Netherlands

 

865

 

130

 

74,749

 

11,212

 

United Kingdom

 

65,489

 

4,441

 

418,039

 

110,641

 

Vietnam (5)

 

 

 

 

 

1,701,812

 

1,309,034

 

Total International

 

283,865

 

98,997

 

7,730,517

 

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.

 

(2)          A gross acre is an acre in which a working interest is owned. A net acre is deemed to exist when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

 

(3)          Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas regardless of whether or not such acreage contains proved reserves. Included within undeveloped acreage are those leased acres (held by production under the terms of a lease) that are not within the spacing unit containing, or acreage assigned to, the productive well so holding such lease.

 

(4)          The Argentina acreage includes 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.

 

(6)          If production is not established, approximately 112,617 gross acres (65,080 net acres), 136,362 gross acres (85,015 net acres) and 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

 

Age

 

Position

 

 

 

 

 

Charles D. Davidson (1)

 

54

 

Chairman of the Board, President, Chief Executive Officer and Director

 

 

 

 

 

Alan R. Bullington (2)

 

52

 

Vice President, International

 

 

 

 

 

Robert K. Burleson (3)

 

46

 

Vice President, Business Administration and President, Noble Energy
     Marketing, Inc.

 

 

 

 

 

Susan M. Cunningham (4)

 

48

 

Senior Vice President, Exploration

 

 

 

 

 

Arnold J. Johnson (5)

 

48

 

Vice President, General Counsel and Secretary

 

 

 

 

 

James L. McElvany (6)

 

50

 

Senior Vice President, Chief Financial Officer and Treasurer

 

 

 

 

 

Richard A. Peneguy, Jr. (7)

 

53

 

Vice President, Offshore

 

 

 

 

 

William A. Poillion, Jr. (8)

 

54

 

Senior Vice President, Production and Drilling

 

 

 

 

 

Ted A. Price (9)

 

44

 

Vice President, Onshore

 

 

 

 

 

David L. Stover (10)

 

46

 

Vice President, Business Development

 

 

 

 

 

Kenneth P. Wiley (11)

 

51

 

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.

 

(2)          Alan R. Bullington was elected Vice President and General Manager, International Division of Samedan Oil Corporation on January 1, 1998 and on April 24, 2001 was elected a Vice President of the Company. Prior thereto, he served as Manager-International Operations and Exploration and as Manager-International Operations. Prior to his employment with Samedan in 1990, he held various management positions within the exploration and production division of Texas Eastern Transmission Company.

 

(3)          Robert K. Burleson was elected a Vice President of the Company on April 24, 2001 and has been in charge of the Company’s Business Administration Department since April 2002. He has also served as President of Noble Gas Marketing, Inc. (now Noble Energy Marketing, Inc.) since June 14, 1995. Prior thereto, he served as Vice President-Marketing for Noble Gas Marketing since its inception in 1994. Previous to his employment 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.

 

(5)          Arnold J. Johnson was elected Vice President, General Counsel and Secretary of the Company on February 1, 2004. Prior 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.

 

(6)          James L. McElvany was elected Senior Vice President, Chief Financial Officer and Treasurer of the Company in July 2002. Prior thereto, he served as Vice President-Finance, Treasurer and Assistant Secretary since July 1999. Prior to July 1999, he had served as Vice President-Controller of the Company since December 1997. Prior thereto, he served as Controller of the Company since December 1983.

 

(7)          Richard A. Peneguy, Jr. was elected a Vice President of the Company on April 24, 2001 and has served as Vice President and General Manager, Offshore Division of Samedan Oil Corporation since 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.

 

(8)          William A. Poillion, Jr. was elected a Senior Vice President of the Company on April 24, 2001 and has served as Senior Vice President-Production and Drilling of Samedan Oil Corporation since January 1998. Prior thereto, he served as Vice President-Production and Drilling of Samedan since November 1990. From March 1, 1985 to October 31, 1990, he served as Manager of Offshore Production and Drilling for Samedan.

 

(9)          Ted A. Price was elected Vice President of the Company and Division Manager for the Onshore Division on January 29, 2002. Previously, he served as Manager of Onshore Exploration since 1999. Mr. Price joined the Company in 1981 as a geologist.

 

(10)          David L. Stover was elected Vice President of Business Development of the Company on December 16, 2002. Previous to his employment with the Company, he was employed by BP as Vice President, Gulf of Mexico Shelf from September 2000 to August 2002. Prior to joining BP, Mr. Stover was employed by Vastar Resources, Inc. as Area Manager for Gulf of Mexico Shelf from April 1999 to September 2000, and prior thereto, as Area Manager for Oklahoma/Arklatex from January 1994 to April 1999.

 

(11)          Kenneth P. Wiley was elected Vice President-Information Systems of the Company in July 1998. Prior thereto, he served as Manager-Information Systems for Samedan Oil Corporation since November 1994.

 

Officers serve until the next annual organizational meeting of the Board of Directors or until their successors are chosen and qualified. No officer or executive officer of the Registrant currently has an employment agreement with the Registrant or any of its subsidiaries. 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.

 

 

 

High

 

Low

 

Dividends
Per Share

 

2003

 

 

 

 

 

 

 

First quarter

 

$

38.62

 

$

33.07

 

$

.04

 

Second quarter

 

$

40.02

 

$

32.37

 

$

.04

 

Third quarter

 

$

40.00

 

$

35.37

 

$

.04

 

Fourth quarter

 

$

45.99

 

$

37.48

 

$

.05

 

2002

 

 

 

 

 

 

 

First quarter

 

$

40.00

 

$

30.76

 

$

.04

 

Second quarter

 

$

40.76

 

$

34.70

 

$

.04

 

Third quarter

 

$

36.34

 

$

26.65

 

$

.04

 

Fourth quarter

 

$

40.50

 

$

31.55

 

$

.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

 

Shares
Outstanding

 

 

 

 

 

Individuals

 

381,843

 

Joint accounts

 

56,013

 

Fiduciaries

 

118,890

 

Institutions

 

64,807

 

Nominees

 

57,176,142

 

Foreign

 

319

 

Total-Excluding Treasury Shares

 

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.

 

 

 

Year Ended December 31,

 

(in thousands, except per share amounts and ratios)

 

2003

 

2002

 

2001

 

2000

 

1999

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues and Income

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

1,010,986

 

$

702,578

 

$

789,513

 

$

730,657

 

$

558,887

 

Net cash provided by operating activities

 

602,770

 

506,955

 

628,154

 

562,578

 

343,935

 

Income from continuing operations

 

89,892

 

8,095

 

85,163

 

137,066

 

28,110

 

Net income

 

77,992

 

17,652

 

133,575

 

191,597

 

49,461

 

 

 

 

 

 

 

 

 

 

 

 

 

Per Share Data

 

 

 

 

 

 

 

 

 

 

 

Basic earnings per share:

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

$

1.58

 

$

0.14

 

$

1.51

 

$

2.45

 

$

0.49

 

Net income

 

$

1.37

 

$

0.31

 

$

2.36

 

$

3.42

 

$

0.87

 

Cash dividends

 

$

0.17

 

$

0.16

 

$

0.16

 

$

0.16

 

$

0.16

 

Year-end stock price

 

$

44.43

 

$

37.55

 

$

35.29

 

$

46.00

 

$

21.44

 

Basic weighted average shares outstanding

 

56,964

 

57,196

 

56,549

 

55,999

 

57,005

 

Financial Position (at year end)

 

 

 

 

 

 

 

 

 

 

 

Property, plant and equipment, net:

 

 

 

 

 

 

 

 

 

 

 

Oil and gas mineral interests, equipment and facilities

 

$

2,099,741

 

$

2,139,785

 

$

1,953,211

 

$

1,485,123

 

$

1,242,370

 

Total assets

 

2,842,649

 

2,730,015

 

2,604,255

 

2,002,819

 

1,543,023

 

Long-term obligations:

 

 

 

 

 

 

 

 

 

 

 

Long-term debt, net of current portion

 

776,021

 

977,116

 

961,118

 

648,567

 

567,524

 

Deferred income taxes

 

163,146

 

201,939

 

176,259

 

117,048

 

83,075

 

Other

 

50,654

 

69,820

 

75,629

 

61,639

 

53,877

 

Shareholders’ equity

 

1,073,573

 

1,009,386

 

1,010,198

 

849,682

 

683,609

 

Ratio of debt-to-book capital (1)

 

.46

 

.50

 

.50

 

.44

 

.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

 

 

Year Ended December 31,

 

 

 

2003

 

2002

 

2001

 

2000

 

1999

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

 

 

 

 

 

 

 

 

 

 

Sales (in millions)

 

$

457.6

 

$

341.1

 

$

487.4

 

$

492.0

 

$

327.6

 

Production (MMcfpd)

 

336.6

 

341.0

 

355.6

 

335.8

 

386.6

 

Average realized price (per Mcf)

 

$

4.13

 

$

2.89

 

$

3.86

 

$

4.09

 

$

2.40

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil

 

 

 

 

 

 

 

 

 

 

 

Sales (in millions)

 

$

358.0

 

$

252.3

 

$

208.6

 

$

124.9

 

$

124.0

 

Production (Bopd)

 

36,014

 

29,114

 

24,973

 

19,650

 

23,690

 

Average realized price (per Bbl)

 

$

27.72

 

$

24.22

 

$

23.49

 

$

18.21

 

$

14.72

 

 

 

 

 

 

 

 

 

 

 

 

 

Royalty sales (in millions)

 

$

23.5

 

$

15.6

 

$

20.9

 

$

17.3

 

$

14.0

 

 

22



 

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

                  The Company ended the year with a stronger balance sheet – total debt was $929.7 million, net of unamortized discount, at year-end 2003, a reduction of $89.3 million from the previous year.

 

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:

 

 

 

Year Ended December 31,

 

(in thousands)

 

2003

 

2002

 

2001

 

Oil and gas mineral interests, equipment and facilities

 

$

492,764

 

$

543,967

 

$

667,499

 

Downstream projects

 

45,134

 

57,646

 

95,716

 

Aspect acquisition

 

 

 

 

 

97,792

 

Corporate and other

 

6,119

 

3,185

 

1,932

 

Total capital expenditures (1)

 

$

544,017

 

$

604,798

 

$

862,939

 

 


(1)          Total capital expenditures include seismic, lease rentals and other miscellaneous expenditures, which are expensed through the statements of operations and are not included in capital expenditures from investing activities.

 

Capital expenditures from investing activities consisted of the following:

 

 

 

Year Ended December 31,

 

(in thousands)

 

2003

 

2002

 

2001

 

Capital expenditures (1)

 

$

527,386

 

$

595,739

 

$

738,706

 

Aspect acquisition, net of cash acquired

 

 

 

 

 

97,792

 

Total capital expenditures from investing activities

 

$

527,386

 

$

595,739

 

$

836,498

 

 


(1)          Capital expenditures do not include expenditures for the methanol plant. Those expenditures are included in cash flows from 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.

 

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Contractual Obligations

 

The following table summarizes the Company’s contractual obligations as of December 31, 2003.

 

(in thousands)

 

Payments Due by Period

 

Contractual
Obligations

 

Total

 

Less Than
1 Year

 

1 to 3
Years

 

4 to 5
Years

 

After 5
Years

 

Outstanding debt

 

$

933,674

 

$

153,674

 

$

330,000

 

$

 

 

$

450,000

 

Asset retirement obligation

 

124,537

 

1,023

 

63,034

 

19,489

 

40,991

 

Drilling obligations

 

3,924

 

3,924

 

 

 

 

 

 

 

Building lease

 

14,292

 

1,588

 

4,764

 

3,176

 

4,764

 

Total contractual cash obligations

 

$

1,076,427

 

$

160,209

 

$

397,798

 

$

22,665

 

$

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.

 

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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.

 

 

 

2003

 

2002

 

2001

 

 

 

Mcfpd

 

Price

 

Mcfpd

 

Price

 

Mcfpd

 

Price

 

United States

 

260,560

 

$

4.75

 

280,836

 

$

3.24

 

311,663

 

$

4.21

 

North Sea

 

13,861

 

$

3.86

 

16,991

 

$

3.14

 

17,830

 

$

3.51

 

Equatorial Guinea (1)

 

39,906

 

$

.25

 

34,382

 

$

.25

 

24,488

 

$

.25

 

Other International (2)

 

22,284

 

$

.41

 

8,799

 

$

.38

 

1,651

 

$

.95

 

Total (3)

 

336,611

 

$

4.13

 

341,008

 

$

2.89

 

355,632

 

$

3.86

 

 


(1)          Natural gas in Equatorial Guinea is under a 25-year contract for $.25 per MMBTU.

 

(2)          Ecuador natural gas volumes are included in Other International production, but are not included in natural gas sales revenues 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.

 

(3)          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 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.

 

 

 

2003

 

2002

 

2001

 

 

 

Bopd

 

Price

 

Bopd

 

Price

 

Bopd

 

Price

 

United States

 

16,084

 

$

26.21

 

13,187

 

$

23.29

 

12,926

 

$

23.02

 

North Sea

 

7,412

 

$

29.95

 

7,847

 

$

25.15

 

4,688

 

$

23.36

 

Equatorial Guinea

 

6,377

 

$

27.93