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, 2002

 

 

 

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)

 

 

 

350 Glenborough Drive, Suite 100
Houston, Texas

 

77067

(Address of principal executive offices)

 

(Zip Code)

 

 

 

(281) 872-3100

(Registrant’s telephone number, including area code)

 

 

 

NOBLE AFFILIATES, INC.

(Registrant’s former name)

 

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 28, 2002:  $1,934,000,000.

Number of shares of Common Stock outstanding as of February 27, 2003:  57,384,490.

 

DOCUMENT INCORPORATED BY REFERENCE

 

Portions of the Registrant’s definitive proxy statement for the 2003 Annual Meeting of Stockholders to be held on April 29, 2003, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2002, are incorporated by reference into Part III.

 

 



 

TABLE OF CONTENTS

 

PART I.

 

 

Item 1.

Business

 

 

 

General

 

 

 

Crude Oil and Natural Gas

 

 

 

Exploration, Exploitation and Development Activities

 

 

 

Production Activities

 

 

 

Acquisitions of Oil and Gas Properties, Leases and Concessions

 

 

 

Marketing

 

 

 

Regulations and Risks

 

 

 

Competition

 

 

 

Unconsolidated Subsidiary

 

 

 

Geographical Data

 

 

 

Employees

 

 

 

Available Information

 

 

Item 2.

Properties

 

 

 

Offices

 

 

 

Crude Oil and Natural Gas

 

 

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 and Related Stockholder Matters

 

 

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

 

 

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

 

 

Item 13.

Certain Relationships and Related Transactions

 

 

Item 14.

Controls and Procedures

 

 

Item 15.

Financial Statement Schedules, Exhibits 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”), the successor to Noble Affiliates, Inc., is a Delaware corporation that has been publicly traded on the New York Stock Exchange for over 20 years. Noble Energy is principally engaged, directly or through its subsidiaries, in the exploration, production and marketing of crude oil and natural gas. The Company is noted for its innovative methods of marketing its international gas reserves through projects such as its methanol plant in Equatorial Guinea and its gas-to-power project in Ecuador.

 

In this report, unless otherwise indicated or the context otherwise requires, the “Company” or the “Registrant” refers to Noble Energy, Inc. and its subsidiaries. Effective December 31, 2001, Energy Development Corporation (“EDC”) was merged into Samedan Oil Corporation (“Samedan”). Effective December 31, 2002, Samedan was merged into Noble Energy, Inc. Effective December 31, 2002, Noble Trading, Inc. (“NTI”) was merged into Noble Gas Marketing, Inc. (“NGM”) under the name of Noble Energy Marketing, Inc. (“NEMI”).

 

As of January 1, 2003, the Company’s wholly-owned subsidiary, NEMI, markets the majority of the Company’s domestic natural gas as well as third-party natural gas. NEMI also markets a portion of the Company’s domestic crude oil as well as third-party crude oil. For more information regarding NEMI’s operations, see “Item 1. Business—Crude Oil and Natural Gas—Marketing” of this Form 10-K.

 

In this report, the following abbreviations are used:

 

Bbl

 

Barrel

 

Mcf

 

Thousand cubic feet

Bbls

 

Barrels

 

Mcfe

 

Thousand cubic feet equivalent

MBbls

 

Thousand barrels

 

MMcf

 

Million cubic feet

Bpd

 

Barrels per day

 

MMcfepd

 

Million cubic feet equivalent per day

Bopd

 

Barrels oil per day

 

MMcfpd

 

Million cubic feet per day

MMBbl

 

Million barrels

 

Bcf

 

Billion cubic feet

MBpd

 

Thousand barrels per day

 

Bcfe

 

Billion cubic feet equivalent

MMBpd

 

Million barrels per day

 

Bcfepd

 

Billion cubic feet equivalent per day

MBopd

 

Thousand barrels oil per day

 

Bcfpd

 

Billion cubic feet per day

MMBopd

 

Million barrels oil per day

 

Tcf

 

Trillion cubic feet

BOE

 

Barrels oil equivalent

 

Tcfe

 

Trillion cubic feet equivalent

MMBoe

 

Million barrels oil equivalent

 

BTU

 

British thermal unit

MMBoepd

 

Million barrels oil equivalent per day

 

BTUpcf

 

British thermal unit per cubic foot

$MM

 

Millions of dollars

 

MMBTU

 

Million British thermal unit

Kwh

 

Kilowatt hour

 

MMBTUpd

 

Million British thermal unit per day

MW

 

Megawatt

 

MTpd

 

Metric tons per day

MWH

 

Megawatt hours

 

LPG

 

Liquefied petroleum gas

 

For reporting BOE or Mcfe, one Bbl of oil or condensate 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. Noble Energy has been engaged in the exploration, production and marketing of crude oil and natural gas since 1932. The Company has exploration, exploitation and production operations domestically and internationally. The domestic areas consist of: offshore in the Gulf of Mexico and California; the Gulf Coast Region (Louisiana, New Mexico and Texas); the Mid-Continent Region (Oklahoma and Kansas); and the Rocky Mountain Region (Colorado, Montana, North Dakota, Wyoming and California). The international areas of operations include Argentina, China, Ecuador, Equatorial Guinea, the Mediterranean Sea (Israel), the North Sea (Denmark, Netherlands and United Kingdom) and Vietnam. For more information regarding Noble Energy’s crude oil and natural gas properties, see “Item 2. Properties—Crude Oil and Natural Gas” of this Form 10-K.

 

Exploration, Exploitation and Development Activities

 

Domestic Offshore. Noble Energy has been actively engaged in exploration, exploitation and development of crude oil and natural gas properties in the Gulf of Mexico (Texas, Louisiana, Mississippi and Alabama) and California since 1968. The Company has shifted its domestic offshore exploration focus to the Gulf of Mexico deep shelf and deepwater areas, and away from the Gulf of Mexico’s conventional shallow shelf, in order to take advantage of lower operating costs, larger prospect sizes and higher rates of return. The Company’s current offshore production is derived from 194 gross wells operated by Noble Energy and 304 gross wells operated by others. At December 31, 2002, the Company held offshore federal leases covering 982,733 gross developed acres and 764,682 gross undeveloped acres on which the Company currently intends to conduct future exploration activities. For more information, see “Item 2.  Properties—Crude Oil and Natural Gas” of this Form 10-K.

 

Domestic Onshore. Noble Energy has been actively engaged in exploration, exploitation and development of crude oil and natural gas properties in three regions since the 1930s. The Gulf Coast Region covers onshore Louisiana, New Mexico and Texas. The Mid-Continent Region covers Oklahoma and Kansas. Properties in the Rocky Mountain Region are located in Colorado, Montana, North Dakota, Wyoming and California.

 

Noble Energy’s current onshore production is derived from 1,496 gross wells operated by the Company and 1,238 gross wells operated by others. At December 31, 2002, the Company held 685,162 gross developed acres and 398,815 gross undeveloped acres onshore on which the Company may conduct future exploration activities. For more information, see “Item 2. Properties—Crude Oil and Natural Gas” of this Form 10-K.

 

Argentina. Noble Energy has been actively engaged in exploration, exploitation and development of crude oil and natural gas properties in Argentina since 1996. The Company’s producing properties are located in southern Argentina in the El Tordillo field, which is characterized by secondary recovery crude oil production from a 10,000 acre reservoir. At December 31, 2002, the Company held 28,988 gross developed acres and 2,398,970 gross undeveloped acres in Argentina on which the Company may conduct future exploration activities. For more information, see “Item 2.  Properties—Crude Oil and Natural Gas” of this Form 10-K.

 

China. Noble Energy has been actively engaged in exploration, exploitation and development of crude oil and natural gas properties in China since 1996. The Company has two concessions offshore China. These concessions, Cheng Dao Xi and Cheng Zi Kou, are contiguous and adjoin non-owned production in the southern portion of Bohai Bay. At December 31, 2002, the Company held 7,413 gross developed acres and 2,569,522 gross undeveloped acres in China on which the Company may conduct future exploration activities. For more information, see “Item 2.  Properties—Crude Oil and Natural Gas” of this Form 10-K.

 

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Ecuador. Noble Energy has been actively engaged in exploration, exploitation and development of crude oil and natural gas properties in Ecuador since 1996. The Company is currently utilizing the gas in the Amistad gas field (offshore Ecuador), which was discovered in the 1970s, to generate electricity through its 100 percent owned natural gas-fired power plant, located near the city of Machala. Currently generating 130 MW, with additional capital investment, the power plant will ultimately be capable of generating 220 MW of electricity into the Ecuadorian power grid. The concession covers 12,355 gross developed acres and 851,771 gross undeveloped acres encompassing the Amistad field. For more information, see “Item 2.  Properties—Crude Oil and Natural Gas” of this Form 10-K.

 

Equatorial Guinea. Noble Energy has been actively engaged in exploration, exploitation and development of crude oil and natural gas properties offshore Equatorial Guinea (West Africa) since 1990. The offshore Equatorial Guinea production is from the Alba field, which produces natural gas and condensate. The majority of the natural gas production is sold to a methanol plant, which began production in the second quarter of 2001. The methanol plant has a 25-year contract to purchase natural gas from the Alba field. The plant is owned by Atlantic Methanol Production Company LLC (“AMPCO”), in which the Company indirectly owns a 45 percent interest through its ownership of Atlantic Methanol Capital Company (“AMCCO”). For more information on the methanol plant, see “Item 1. Business—Unconsolidated Subsidiary” of this Form 10-K.

 

At December 31, 2002, the Company held 45,203 gross developed acres and 266,754 gross undeveloped acres offshore Equatorial Guinea on which the Company may conduct future exploration activities. For more information, see “Item 2.  Properties—Crude Oil and Natural Gas” of this Form 10–K.

 

Israel. Noble Energy has been actively engaged in exploration, exploitation and development of crude oil and natural gas properties in the Mediterranean Sea, offshore Israel, since 1998. The Company owns a 47 percent interest in 11 licenses and two leases. At December 31, 2002, the Company held 123,552 gross developed acres and 1,028,796 gross undeveloped acres located about 20 miles offshore Israel in water depths ranging from 700 feet to 5,000 feet. Noble Energy and its partners announced on June 25, 2002 they had executed a definitive agreement for the sale of natural gas to Israel Electric Corporation (“IEC”). For more information, see “Item 2. Properties—Crude Oil and Natural Gas” of this Form 10-K.

 

North Sea. Noble Energy has been actively engaged in exploration, exploitation and development of crude oil and natural gas properties in the North Sea (Denmark, Netherlands and United Kingdom) since 1996. At December 31, 2002, the Company held 81,675 gross developed acres and 677,029 gross undeveloped acres on which the Company may conduct future exploration activities. For more information, see “Item 2.  Properties—Crude Oil and Natural Gas” of this Form 10-K.

 

Vietnam. Noble Energy owns a 77 percent interest in two offshore blocks totaling 1,701,812 gross undeveloped acres in the Nam Con Son Basin. For more information, see “Item 2.  Properties—Crude Oil and Natural Gas” of this Form 10-K.

 

Production Activities

 

Operated Property Statistics. The percentage of crude oil and natural gas wells operated and the percentage of sales volume from operated properties are shown in the following table as of December 31:

 

 

 

2002

 

2001

 

2000

 

(in percentages)

 

Oil

 

Gas

 

Oil

 

Gas

 

Oil

 

Gas

 

Operated well count basis

 

23.3

 

62.8

 

24.8

 

60.6

 

23.1

 

66.0

 

Operated sales volume basis

 

29.3

 

45.1

 

37.2

 

52.3

 

48.3

 

64.5

 

 

3



 

Net Production. The following table sets forth Noble Energy’s net crude oil and natural gas production, including royalty, for the three years ended December 31:

 

 

 

2002

 

2001

 

2000

 

Crude Oil Production (MMBbl)

 

12.4

 

11.2

 

9.4

 

Natural Gas Production (Bcf)

 

141.5

 

154.2

 

148.7

 

 

Crude Oil and Natural Gas Equivalents. The following table sets forth Noble Energy’s net production stated in crude oil and natural gas equivalent volumes, for the three years ended December 31:

 

 

 

2002

 

2001

 

2000

 

Total Crude Oil Equivalents (MMBoe)

 

36.0

 

36.9

 

34.2

 

Total Natural Gas Equivalents (Bcfe)

 

216.0

 

221.3

 

205.4

 

 

Acquisitions of Oil and Gas Properties, Leases and Concessions

 

During 2002, Noble Energy spent approximately $8 million on the purchase of proved crude oil and natural gas properties. The Company spent approximately $98 million in 2001 and $99 million in 2000 on proved properties. For more information, see “Item 2.  Properties—Crude Oil and Natural Gas” of this Form 10-K.

 

During 2002, Noble Energy spent approximately $31 million on acquisitions of unproved properties. The Company spent approximately $81 million in 2001 and $18 million in 2000 on acquisitions of unproved properties. These properties were acquired primarily through various offshore lease sales, domestic onshore lease acquisitions and international concession negotiations. For more information, see “Item 2.  Properties—Crude Oil and Natural Gas” of this Form 10-K.

 

Marketing

 

NEMI seeks opportunities to enhance the value of the Company’s domestic natural gas by marketing directly to end users and aggregating gas to be sold to natural gas marketers and pipelines. During 2002, approximately 83 percent of NEMI’s total sales were to end users. NEMI is also actively involved in the purchase and sale of natural gas from other producers. Such third-party natural gas may be purchased from non-operators who own working interests in the Company’s wells or from other producers’ properties in which the Company may not own an interest. NEMI, through its wholly-owned subsidiary, Noble Gas Pipeline, Inc., engages in the installation, purchase and operation of natural gas gathering systems.

 

Noble Energy has a short-term natural gas sales contract with NEMI, whereby the Company is paid an index price for all natural gas sold to NEMI. The Company sold approximately 66 percent of its natural gas production to NEMI in 2002. Third-party sales, including derivative transactions, are recorded as gathering, marketing and processing revenues. NEMI records the amount paid to Noble Energy and third parties as gathering, marketing and processing costs and expenses. All intercompany sales and expenses are eliminated in the Company’s consolidated financial statements. The Company has a small number of long-term natural gas contracts representing less than four percent of its total natural gas sales.

 

Crude oil produced by the Company is sold to purchasers in the United States and foreign locations at various prices depending on the location and quality of the crude oil.  The Company has no long-term contracts with purchasers of its crude oil production. Crude oil and condensate are distributed through pipelines and by trucks to gatherers, transportation companies and end users. NEMI markets approximately 30 percent of the Company’s crude oil production as well as certain third-party crude oil. The Company records all of NEMI’s sales as gathering, marketing and processing revenues and records cost of sales in gathering, marketing and processing costs. All intercompany sales and expenses are eliminated in the Company’s consolidated financial statements.

 

4



 

Crude oil prices are affected by a variety of factors that are beyond the control of the Company. The Company’s average crude oil price increased $.68 from $23.30 per Bbl in 2001 to $23.98 per Bbl in 2002. Due to the volatility of crude oil prices, the Company, from time to time, has used hedging instruments and may do so in the future as a means of controlling its exposure to price changes. For additional information, see “Item 7a. Quantitative and Qualitative Disclosures About Market Risk” and “Item 8. Financial Statements and Supplementary Data” of this Form 10-K.

 

Substantial competition in the natural gas marketplace continued in 2002. The Company’s average natural gas price decreased from $3.98 per Mcf in 2001 to $2.92 per Mcf in 2002. Due to the volatility of natural gas prices, the Company, from time to time, has used hedging instruments and may do so in the future as a means of controlling its exposure to price changes. For additional information, see “Item 7a. Quantitative and Qualitative Disclosures About Market Risk” and “Item 8. Financial Statements and Supplementary Data” of this Form 10-K.

 

The largest single non-affiliated purchaser of the Company’s crude oil production in 2002 accounted for approximately 15 percent of the Company’s crude oil sales, representing approximately three percent of total revenues. The five largest purchasers accounted for approximately 50 percent of total crude oil sales. The largest single non-affiliated purchaser of the Company’s natural gas production in 2002 accounted for approximately six percent of its natural gas sales, representing approximately two percent of total revenues. The five largest purchasers accounted for approximately 16 percent of total natural gas sales. The Company does not believe that its loss of a major crude oil or natural gas purchaser would have a material effect on the Company.

 

Regulations and Risks

 

General. Exploration for and production and sale of crude oil and natural gas are extensively regulated at the international, national, state and local levels. Crude oil and natural gas development and production activities are subject to various laws and regulations (and orders of regulatory bodies pursuant thereto) governing a wide variety of matters, including allowable rates of production, prevention of waste and pollution and protection of the environment. Laws affecting the crude oil and natural gas industry are under constant review for amendment or expansion and frequently increase the regulatory burden on companies. Noble Energy’s ability to economically produce and sell crude oil and natural gas is affected by a number of legal and regulatory factors, including federal, state and local laws and regulations in the United States and laws and regulations of foreign nations. Many of these governmental bodies have issued rules and regulations that are often difficult and costly to comply with, and that carry substantial penalties for failure to comply. These laws, regulations and orders may restrict the rate of crude oil and natural gas production below the rate that would otherwise exist in the absence of such laws, regulations and orders. The regulatory burden on the crude oil and natural gas industry increases its costs of doing business and consequently affects the Company’s profitability.

 

Certain Risks. In the Company’s exploration operations, losses may occur before any accumulation of crude oil or natural gas is found. If crude oil or natural gas is discovered, no assurance can be given that sufficient reserves will be developed to enable the Company to recover the costs incurred in obtaining the reserves or that reserves will be developed at a sufficient rate to replace reserves currently being produced and sold. The Company’s international operations are also subject to certain political, economic and other uncertainties including, among others, risk of war, expropriation, renegotiation or modification of existing contracts, taxation policies, foreign exchange restrictions, international monetary fluctuations and other hazards arising out of foreign governmental sovereignty over areas in which the Company conducts operations.

 

Environmental Matters. As a developer, owner and operator of crude oil and natural gas properties, the Company is subject to various federal, state, local and foreign country laws and regulations relating to the discharge of materials into, and the protection of, the environment. The unauthorized release or discharge of crude oil or certain other regulated substances from the Company’s domestic onshore or offshore facilities could subject the Company to

 

5



 

liability under federal laws and regulations, including the Oil Pollution Act of 1990, the Outer Continental Shelf Lands Act and the Federal Water Pollution Control Act, as amended. These laws, among others, impose liability for such a release or discharge for pollution cleanup costs, damage to natural resources and the environment, various forms of direct and indirect economic losses, civil or criminal penalties, and orders or injunctions, including those that can require the suspension or cessation of operations causing or impacting or potentially impacting such release or discharge. The liability under these laws for a substantial such release or discharge, subject to certain specified limitations on liability, may be extraordinarily large. If any pollution was caused by willful misconduct, willful negligence or gross negligence within the privity and knowledge of the Company, or was caused primarily by a violation of federal regulations, the Federal Water Pollution Control Act provides that such limitations on liability do not apply. Certain of the Company’s facilities are subject to regulations that require the preparation and implementation of spill prevention control and countermeasure plans relating to the prevention of, and preparation for, the possible discharge of crude oil into navigable waters.

 

The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as “Superfund,” imposes liability on certain classes of persons that generated a hazardous substance that has been released into the environment or that own or operate facilities or vessels onto or into which hazardous substances are disposed. The Resource Conservation and Recovery Act, as amended, (“RCRA”) and regulations promulgated thereunder, regulate hazardous waste, including its generation, treatment, storage and disposal. CERCLA currently exempts crude oil, and RCRA currently exempts certain crude oil and natural gas exploration and production drilling materials, such as drilling fluids and produced waters, from the definitions of hazardous substance and hazardous waste, respectively. The Company’s operations, however, may involve the use or handling of other materials that may be classified as hazardous substances and hazardous wastes, and therefore, these statutes and regulations promulgated under them would apply to the Company’s generation, handling and disposal of these materials. In addition, there can be no assurance that such exemptions will be preserved in future amendments of such acts, if any, or that more stringent laws and regulations protecting the environment will not be adopted.

 

Certain of the Company’s facilities may also be subject to other federal environmental laws and regulations, including the Clean Air Act with respect to emissions of air pollutants.

 

Certain state or local laws or regulations and common law may impose liabilities in addition to, or restrictions more stringent than, those described herein.

 

The environmental laws, rules and regulations of foreign countries are generally less stringent than those of the United States, and therefore, the requirements of such jurisdictions do not generally impose an additional compliance burden on the Company or on its subsidiaries.

 

The Company has made and will continue to make expenditures in its efforts to comply with environmental requirements. The Company does not believe that it has to date expended material amounts in connection with such activities or that compliance with such requirements will have a material adverse effect upon the capital expenditures, earnings or competitive position of the Company. Although such requirements do have a substantial impact upon the energy industry, generally they do not appear to affect the Company any differently or to any greater or lesser extent than other companies in the industry.

 

Insurance. The Company has various types of insurance coverages as are customary in the industry which include, in various degrees, general liability, well control, pollution and physical damage insurance. The Company believes the coverages and types of insurance are adequate.

 

Competition

 

The oil and gas industry is highly competitive. Many companies and individuals are engaged in exploring for crude oil and natural gas and acquiring crude oil and natural gas properties, resulting in a high degree of competition for

 

6



 

desirable exploratory and producing properties. A number of the companies with which the Company competes are larger and have greater financial resources than the Company.

 

The availability of a ready market for the Company’s crude oil and natural gas production depends on numerous factors beyond its control, including the level of consumer demand, the extent of worldwide crude oil and natural gas production, the costs and availability of alternative fuels, the costs and proximity of pipelines and other transportation facilities, regulation by state and federal authorities and the costs of complying with applicable environmental regulations.

 

Unconsolidated Subsidiary

 

Prior to January 2002, AMCCO was a 50 percent owned joint venture that owned an indirect 90 percent interest in AMPCO, which completed construction of a methanol plant in Equatorial Guinea in the second quarter of 2001. During 1999, AMCCO issued $125 million Series A-1 and $125 million Series A-2 senior secured notes due December 15, 2004 to fund the remaining construction payments. On January 2, 2002, the Company’s partner in AMCCO directed AMCCO to sell 50 percent of its interest in AMPCO as a component of the partner’s sale of its Equatorial Guinea assets. The proceeds of the AMPCO sale were used to repay in full AMCCO’s $125 million Series A-1 Notes on January 28, 2002 and to make a distribution to the Company’s partner. Since the Company’s partner in AMCCO no longer retains an economic interest in AMPCO, the Company began consolidating AMCCO’s debt in 2002, thereby including the $125 million Series A-2 Notes in the Company’s balance sheet effective January 28, 2002. The terms of the $125 million Series A-2 Notes remain unchanged.

 

The plant construction started during 1998 and initial production of commercial grade methanol commenced May 2, 2001. The total construction costs of the plant and supporting facilities as of December 31, 2002 were $417 million, with the Company responsible for $208.5 million. The plant is designed to produce 2,500 MTpd of methanol, which equates to approximately 20,000 Bpd. At this level of production, the plant would purchase approximately 125 MMcfpd from the 34 percent owned Alba field. The methanol plant has a 25-year contract to purchase natural gas from the Alba field. For more information, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data—Note 9 - Unconsolidated Subsidiary” of this Form 10-K.

 

Geographical Data

 

The Company has operations throughout the world and manages its operations by country. Information is grouped into five components that are all primarily in the business of natural gas and crude oil exploration, exploitation and production: United States, Equatorial Guinea, Mediterranean Sea, North Sea and Other International. For more information, see “Item 8. Financial Statements and Supplementary Data—Note 11 - Geographical Data” of this Form 10-K.

 

Employees

 

The total number of employees of the Company increased during the year from 610 at December 31, 2001, to 624 at December 31, 2002. Eighty foreign nationals worked in Noble Energy offices in China, Ecuador, Israel and Vietnam as of December 31, 2002.

 

Available Information

 

The Company’s website address is www.nobleenergyinc.com. Available on this website under “Investor Relations -Investor Relations Menu - SEC Filings,” free of charge, are Noble Energy’s annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after such materials are electronically filed with or furnished to the United States Securities and Exchange Commission (“SEC”).

 

7



 

Item 2.    Properties.

 

Offices

 

The principal corporate office of the Registrant is located in Houston, Texas. The Company maintains offices for international, domestic onshore and domestic offshore operations in Houston, Texas. The Company also maintains offices in China, Ecuador, Israel, the United Kingdom and Vietnam. NEMI’s office is located in Houston, Texas.  The Company also maintains offices in Ardmore, Oklahoma for centralized accounting, division orders, employee benefits and related administrative functions.

 

Crude Oil and Natural Gas

 

The Company, directly or through its subsidiaries or various arrangements with other companies, searches for potential crude oil and natural gas properties, seeks to acquire exploration rights in areas of interest and conducts exploratory activities. These activities include geophysical and geological evaluation and exploratory drilling, where appropriate, on properties for which it acquired exploration rights. During 2002, Noble Energy drilled or participated in the drilling of 194 gross (90.0 net) wells, comprised of 59 gross (16.1 net) international wells and 135 gross (73.9 net) domestic wells. For more information regarding Noble Energy’s oil and gas properties, see “Item 1. Business—Crude Oil and Natural Gas” of this Form 10-K.

 

Domestic Offshore. Noble Energy’s first operated commercial deepwater natural gas discovery in East Breaks 421 (Lost Ark) commenced production ahead of schedule in the second quarter of 2002. Production began at an initial rate of 40 MMcfpd. Noble Energy has a 48 percent working interest in Lost Ark.

 

Another deepwater natural gas discovery, Green Canyon 136 A-8 (Shasta), commenced production in January 2003 at 25 MMcfpd. Noble Energy has a 25 percent working interest in Shasta.

 

Green Canyon 282 (Boris), a deepwater crude oil discovery, commenced production from its first well during the first quarter of 2003 at 9,500 Bopd. The second well is expected to commence production by mid-year 2003 at an additional 8,000 Bopd. Noble Energy has a 25 percent working interest in Boris.

 

Another deepwater crude oil discovery, Viosca Knoll 917/961/962 (Swordfish), is expected to commence production during 2004.

 

Highlights of the 2002 deep shelf program include several key properties. In the first quarter, Eugene Island 97 #3 (Thunderbolt), in which the Company has a 25 percent working interest, commenced production at 15 MMcfpd. During the second quarter, Main Pass 108 B-3 commenced production at 15 MMcfpd, and Viosca Knoll 68 #4 commenced production at 16 MMcfpd. The Company has a 25 percent and 30 percent working interest in these wells, respectively. Noble Energy has a 31 percent working interest in Ship Shoal 225 #1 that commenced production in the third quarter at 750 Bopd. During the fourth quarter, production of 36 MMcfpd commenced from the Viosca Knoll 384 A-1 and A-2. Noble Energy has a 24 percent working interest in these wells.

 

During 2002, the Company expensed eight exploratory wells related to its offshore activity.

 

Noble Energy was the successful bidder, alone or with partners, on 17 of 20 lease blocks at the Central Gulf of Mexico Outer Continental Shelf Sale 182. Fifteen of the Company’s 17 bids were approved with two being rejected. Of the 15 approved bids, nine were on blocks in deepwater, five were on blocks in the deep shelf, and the remaining block was in the conventional shelf. Approved bids totaled approximately $9.2 million net to the Company’s interest. Noble Energy will be the designated operator on 12 of the blocks.

 

8



 

Domestic Onshore. During the fourth quarter of 2001, Noble Energy acquired all of the Gulf Coast onshore producing properties of Aspect Energy. As part of the transaction, Noble Energy and Aspect Energy established a joint venture to explore for and produce crude oil and natural gas. The area of mutual interest extends from Matagorda County, Texas to Lafayette Parish, Louisiana and includes 7,250 square miles of 3D seismic. This extensive 3D seismic database enhances Noble Energy’s long-term domestic onshore position by providing a significant number of future exploration opportunities. During 2002, the joint venture drilled 45 wells, of which 26 wells, or 58 percent, were successful.

 

During the second quarter of 2002, the Company acquired an interest in the Bendito project in Matagorda County, Texas. The acquisition consisted of five producing wells in which Noble Energy owns a 35 percent working interest, 3,000 gross developed acres, 8,100 gross undeveloped acres, multiple 3D seismic defined prospects and a license to 45 square miles of proprietary 3D seismic data. The Steele #1, in which the Company owns a 29 percent working interest, was the initial exploratory test well in the Lower Frio trend of the Bendito project, drilled in late 2002 and tested at 5.1 MMcfpd and 310 Bopd.

 

Another domestic onshore exploration project in 2002 was Wildcat Ridge, which includes a 120 square mile proprietary 3D seismic survey in southeast Texas and southwest Louisiana. Initial drilling commenced in late 2002 with the Doornbos #1, in which Noble Energy owns a 35 percent working interest, discovering Miocene reserves in multiple zones. The W&T Offshore #1, in which the Company owns a 38 percent working interest, spud in January 2003, is the second successful well within the project. An additional well, the Noble Heirs #1, in which the Company owns a 38 percent working interest, commenced drilling in February 2003. In addition, technical analysis continues on several other identified prospects within the Wildcat Ridge project area.

 

During 2002, the Company expensed 24 exploratory wells related to its onshore activity.

 

Argentina. Noble Energy participated with a 13 percent working interest in 37 exploitation wells in the El Tordillo field during 2002. The Company has been awarded, and is awaiting final government approval of, a crude oil and natural gas exploration permit of approximately 1.2 million acres. The permit is located in the Cuyo Basin of Mendoza Province in western Argentina. The Company was the successful bidder on an adjacent permit of approximately 1.1 million acres.

 

China. Noble Energy completed its development of the Cheng Dao Xi (CDX) field in December 2002. The Company has a 57 percent working interest in CDX, which is located on the south side of Bohai Bay off the coast of China. Initial production of 6,000 Bopd (3,420 Bopd net to Noble Energy) from CDX commenced on January 13, 2003. The facilities on CDX have production capacity of 10,000 Bopd.

 

During 2002, the Company expensed three exploratory wells related to its activity in China. In early February 2003, an exploratory well in the South China Sea commenced drilling, with the Company having a 50 percent working interest.

 

Ecuador. In September 2002, Noble Energy commenced operations of its 100 percent owned fully integrated gas-to-power project ahead of schedule. The project includes the Amistad field, which is located in the shallow waters of the Gulf of Guayaquil near the coast of Ecuador. To date, Noble Energy has completed three development wells in the Amistad field that supply approximately 30 MMcfpd of natural gas to the Machala power plant. The power plant is located on the coast near Machala, Ecuador and connects to the Amistad field via a 40-mile pipeline. Machala Power is the only natural gas-fired commercial power generator in Ecuador. The Machala power plant currently has generating capacity of 130 MW from twin General Electric Frame 6Fa turbines.

 

Equatorial Guinea. During 2002, Noble Energy and its partners obtained approval from the government of Equatorial Guinea for phases 2A and 2B Alba field expansion projects. Phase 2A, which is scheduled to be

 

9



 

completed in the fourth quarter of 2003, is expected to increase gross condensate production by approximately 29,000 Bopd (8,900 Bopd net to Noble Energy).

 

Phase 2B, which is scheduled to be completed during the fourth quarter of 2004, is expected to increase gross production of LPG by approximately 14,000 Bpd (3,900 Bpd net to Noble Energy) and gross condensate production by approximately 6,000 Bopd (1,700 Bopd net to Noble Energy). The project includes increasing processing capacity, storage and offloading facilities at the existing LPG plant. A fractionation unit will also be installed.

 

Following the completion of phases 2A and 2B, gross condensate and LPG capacity will be approximately 54,000 Bopd (16,000 Bopd net to Noble Energy) and 16,000 Bpd (4,500 Bpd net to Noble Energy), respectively.

 

Noble Energy holds a 34 percent working interest in the Alba field and related condensate production facilities, a 28 percent working interest in the Bioko Island LPG plant and a 45 percent working interest in the AMPCO plant that  purchases and processes approximately 125 MMcfpd of natural gas into 2,500 MTpd of methanol. During 2002, 17 shipments of methanol were delivered, eight to European markets and nine to markets in the United States.

 

Israel. The Company and its partners signed a definitive agreement to provide approximately 170 MMcfpd of natural gas for use in IEC’s power plants. Natural gas will be produced from the Mari-B field, offshore Israel, which was discovered in 2000. Production is anticipated to begin during the fourth quarter of 2003. Noble Energy has a 47 percent working interest in the project.

 

North Sea. The Company continued to focus on production and exploration growth in 2002. Two new licenses (P1047 and P1041) were awarded to Noble Energy in 2002 from the United Kingdom’s 20th Licenses Bid Round. The Company expects to participate in five exploration wells in 2003, including the Company-operated Joppa prospect.

 

Vietnam. The Company continues to evaluate prospects in the two blocks of the Nam Con Son Basin in order to supplement the Swan discovery well of 2001. During 2002, the Company expensed one exploratory well.

 

10



 

Net Exploratory and Developmental Wells. The following table sets forth, for each of the last three years, the number of net exploratory and development wells drilled by or on behalf of Noble Energy. An exploratory well is a well drilled to find and produce crude oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a known reservoir. A development well, for purposes of the following table and as defined in the rules and regulations of the SEC, is a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of crude oil or natural gas, or in the case of a dry hole, to the reporting of abandonment to the appropriate agency.

 

 

 

Net Exploratory Wells

 

Net Development Wells

 

 

 

Productive(1)

 

Dry(2)

 

Productive(1)

 

Dry(2)

 

Year Ended December 31,

 

U.S.

 

Int’l

 

U.S.

 

Int’l

 

U.S.

 

Int’l

 

U.S.

 

Int’l

 

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

 

2000

 

17.86

 

3.94

 

10.59

 

1.00

 

101.89

 

5.99

 

4.17

 

.57

 

 


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

 

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

 

At January 31, 2003, Noble Energy was drilling 5 gross (2.3 net) exploratory wells and 5 gross (.8 net) development wells. These wells are located onshore in Louisiana, Wyoming and Argentina and offshore in the Gulf of Mexico and Equatorial Guinea. These wells have objectives ranging from approximately 5,110 feet to 14,075 feet. The drilling cost to Noble Energy of these wells will be approximately $7 million if all are dry and approximately $11 million if all are completed as producing wells.

 

11



 

Crude Oil and Natural Gas Wells. The number of productive crude oil and natural gas wells in which Noble Energy held an interest as of December 31 follows:

 

 

 

2002(1)(2)

 

2001(1)(2)

 

2000(1)(2)

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Crude Oil Wells

 

 

 

 

 

 

 

 

 

 

 

 

 

United States – Onshore

 

1,131.0

 

458.7

 

1,364.5

 

573.6

 

1,341.5

 

564.0

 

United States – Offshore

 

232.5

 

95.7

 

212.5

 

120.0

 

210.5

 

119.2

 

International

 

687.0

 

81.3

 

670.0

 

75.7

 

604.0

 

66.2

 

Total

 

2,050.5

 

635.7

 

2,247.0

 

769.3

 

2,156.0

 

749.4

 

Natural Gas Wells

 

 

 

 

 

 

 

 

 

 

 

 

 

United States – Onshore

 

1,603.0

 

1,006.6

 

1,673.5

 

1,025.7

 

1,532.5

 

947.1

 

United States – Offshore

 

265.5

 

184.9

 

333.5

 

143.3

 

300.5

 

133.4

 

International

 

42.0

 

13.1

 

38.0

 

8.4

 

31.0

 

3.5

 

Total

 

1,910.5

 

1,204.6

 

2,045.0

 

1,177.4

 

1,864.0

 

1,084.0

 

 


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

 

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

 

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

 

 

 

2002

 

2001

 

2000

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Multiple Completions

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil

 

12.0

 

6.0

 

13.5

 

6.9

 

13.5

 

6.9

 

Natural Gas

 

28.5

 

8.9

 

36.5

 

14.0

 

36.5

 

14.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Not Producing (Shut-in)

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil

 

565.0

 

212.3

 

391.0

 

179.2

 

386.0

 

177.5

 

Natural Gas

 

121.0

 

73.0

 

100.0

 

36.3

 

62.0

 

20.6

 

 

At year-end 2002, Noble Energy had less than eight percent of its crude oil and natural gas sales volumes committed to long-term supply contracts and had no similar agreements with foreign governments or authorities.

 

Since January 1, 2002, no crude oil or natural gas reserve information has been filed with, or included in any report to any federal authority or agency other than the SEC and the Energy Information Administration (“EIA”). Noble Energy files Form 23, including reserve and other information, with the EIA.

 

12



 

Average Sales Price. The following table sets forth, for each of the last three years, the average sales price per unit of crude oil produced and per unit of natural gas produced, and the average production cost per unit.

 

 

 

Year Ended December 31,

 

 

 

2002

 

2001

 

2000

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

$

23.08

 

$

22.88

 

$

23.75

 

International

 

$

24.98

 

$

23.98

 

$

28.28

 

 

 

 

 

 

 

 

 

Combined(2)

 

$

23.98

 

$

23.30

 

$

24.95

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

$

3.20

 

$

4.24

 

$

3.90

 

International

 

$

1.18

 

$

1.60

 

$

2.45

 

 

 

 

 

 

 

 

 

Combined(3)

 

$

2.92

 

$

3.98

 

$

3.80

 

 

 

 

 

 

 

 

 

Average production (lifting) cost per Mcfe:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

$

.70

 

$

.66

 

$

.59

 

International

 

$

.79

 

$

.46

 

$

.64

 

 

 

 

 

 

 

 

 

Combined

 

$

.70

 

$

.60

 

$

.59

 

 


 

(1)   Net production amounts used in this calculation include royalties.

 

(2)   Reflects a reduction of  $.02 per Bbl in 2002 and $2.92 per Bbl in 2000 from hedging in the United States.

 

(3)   Reflects an increase of $.04 per Mcf in 2002 and $.03 per Mcf in 2001 from hedging in the United States.

 

13



 

 

Significant Offshore Undeveloped Lease Holdings (interests rounded to nearest whole percent)

 

Block

 

Net Working
Interest (%)

 

 

 

 

 

East Breaks

 

 

 

279*

 

33

 

420*

 

48

 

464*

 

48

 

465*

 

48

 

475*

 

100

 

510*

 

33

 

519*

 

100

 

563*

 

100

 

 

 

 

 

Green Canyon

 

 

 

23

 

100

 

27

 

43

 

85*

 

50

 

142

 

100

 

185*

 

100

 

186*

 

100

 

187*

 

100

 

227*

 

100

 

228*

 

100

 

303*

 

40

 

507*

 

50

 

723*

 

100

 

724*

 

100

 

768*

 

100

 

955*

 

7

 

958*

 

25

 

 

 

 

 

West Cameron

 

 

 

136

 

40

 

392

 

100

 

393

 

100

 

400

 

100

 

419

 

100

 

422

 

50

 

438

 

100

 

443

 

100

 

446

 

100

 

 

 

 

 

Mustang Island

 

 

 

829

 

80

 

830

 

80

 

 

 

 

 

Vermilion

 

 

 

195

 

25

 

207

 

25

 

208

 

25

 

228

 

100

 

230

 

100

 

232

 

50

 

235

 

100

 

280

 

50

 

285

 

100

 

300

 

50

 

353

 

100

 

377

 

100

 

391

 

100

 

 

 

 

 

Garden Banks

 

 

 

25

 

50

 

154

 

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

 

98

 

50

 

156

 

67

 

278

 

50

 

315

 

40

 

 

 

 

 

Ship Shoal

 

 

 

73

 

50

 

 

 

 

 

Galveston

 

 

 

249-L

 

50

 

250-L

 

50

 

274-L

 

50

 

275-L

 

50

 

277-L

 

50

 

340-S

 

50

 

341-S

 

50

 

 

 

 

 

South Marsh Island

 

 

 

38

 

100

 

64

 

67

 

70

 

50

 

145

 

100

 

167

 

100

 

195

 

50

 

 

 

 

 

Mississippi Canyon

 

 

 

26*

 

75

 

70*

 

75

 

71*

 

75

 

123*

 

75

 

159*

 

75

 

204*

 

100

 

524*

 

50

 

583*

 

50

 

595*

 

24

 

602*

 

75

 

639*

 

24

 

665*

 

50

 

769*

 

100

 

811*

 

30

 

837*

 

40

 

849*

 

34

 

855*

 

30

 

856*

 

30

 

857*

 

30

 

896*

 

67

 

900*

 

30

 

901*

 

30

 

911*

 

40

 

999*

 

30

 

1000*

 

30

 

 

 

 

 

Brazos

 

 

 

308-L

 

50

 

336-L

 

50

 

337-L

 

50

 

368-L

 

25

 

543

 

100

 

 

 

 

 

Ewing Bank

 

 

 

834

 

14

 

949

 

52

 

993

 

98

 

995

 

43

 

996

 

43

 

 

 

 

 

Eugene Island

 

 

 

96

 

25

 

317

 

67

 

 

 

 

 

High Island

 

 

 

A-218

 

100

 

A-230

 

100

 

A-426

 

33

 

A-435

 

33

 

A-516

 

100

 

 

 

 

 

Viosca Knoll

 

 

 

23

 

100

 

344

 

100

 

383

 

24

 

697

 

50

 

820

 

50

 

864*

 

35

 

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.

 

14



 

The developed and undeveloped acreage (including both leases and concessions) that Noble Energy held as of December 31, 2002, 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

 

 

 

 

 

2,657

 

506

 

California

 

4,902

 

2,048

 

5,002

 

3,832

 

Colorado

 

67,339

 

58,945

 

28,705

 

18,342

 

Kansas

 

93,918

 

52,833

 

17,803

 

11,907

 

Louisiana

 

52,151

 

9,162

 

38,023

 

10,002

 

Michigan

 

 

 

 

 

1,876

 

427

 

Mississippi

 

878

 

34

 

1,884

 

51

 

Montana

 

196,028

 

116,677

 

5,488

 

2,224

 

New Mexico

 

2,117

 

826

 

2,520

 

1,873

 

North Dakota

 

678

 

339

 

4,082

 

3,087

 

Oklahoma

 

144,373

 

52,972

 

19,191

 

7,207

 

Texas

 

86,073

 

40,144

 

196,038

 

61,008

 

Utah

 

5,160

 

2,433

 

4,956

 

4,254

 

Wyoming

 

31,545

 

18,831

 

70,590

 

47,272

 

Total United States Onshore

 

685,162

 

355,244

 

398,815

 

171,992

 

United States Offshore (Federal Waters)

 

 

 

 

 

 

 

 

 

Alabama

 

103,680

 

43,430

 

41,661

 

25,123

 

California

 

38,834

 

12,039

 

52,364

 

9,422

 

Louisiana

 

591,963

 

251,317

 

407,705

 

288,823

 

Mississippi

 

28,171

 

15,809

 

119,024

 

55,199

 

Texas

 

220,085

 

100,490

 

143,928

 

92,094

 

Total United States Offshore (Federal Waters)

 

982,733

 

423,085

 

764,682

 

470,661

 

International

 

 

 

 

 

 

 

 

 

Argentina

 

28,988

 

3,977

 

2,398,970

 

2,326,204

 

China

 

7,413

 

4,225

 

2,569,522

 

1,328,314

 

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

 

1,028,796

 

338,538

 

Netherlands

 

865

 

130

 

74,749

 

11,212

 

United Kingdom

 

80,810

 

4,646

 

521,230

 

153,807

 

Vietnam

 

 

 

 

 

1,701,812

 

1,309,034

 

Total International

 

299,186

 

99,202

 

9,494,654

 

6,444,108

 

 

 

 

 

 

 

 

 

 

 

Total

 

1,967,081

 

877,531

 

10,658,151

 

7,086,761

 

 


(1)          Developed acreage is acreage spaced or assignable to productive wells.

 

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

 

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

 

(4)          The Argentina acreage includes two concessions totaling 2,314,633 acres subject to final regulatory approval.

 

15



 

Item 3.    Legal Proceedings.

 

(a)     The Company and its subsidiaries are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the inherent uncertainties in any litigation. The Company is defending itself vigorously in all such matters and does not believe that the ultimate disposition of such proceedings will have a material adverse effect on the Company’s consolidated financial position, results of operations or liquidity.

 

(b)         On October 15, 2002, Noble Gas Marketing, Inc., Samedan Oil Corporation and Aspect Resources L.L.C., collectively referred to as the “Noble Defendants,” filed proofs of claim in the United States Bankruptcy Court for the Southern District of New York in response to bankruptcy filings by Enron Corporation and certain of its subsidiaries and affiliates, including Enron North America Corporation (“ENA”), under Chapter 11 of the U.S. Bankruptcy Code. The proofs of claim relate to certain natural gas sales agreements and aggregate approximately $18 million.

 

                        On December 13, 2002, ENA filed a complaint in which it objected to the Noble Defendants’ proofs of claim, sought recovery of approximately $60 million from the Noble Defendants under the natural gas sales agreements, sought declaratory relief in respect of the offset rights of the Noble Defendants and sought to invalidate the arbitration provisions contained in certain of the agreements in issue. The Noble Defendants intend to vigorously defend against ENA’s claims and do not believe that the ultimate disposition of the bankruptcy proceeding will have a material adverse effect on the Company’s consolidated financial position, results of operations or liquidity.

 

Item 4.    Submission of Matters to a Vote of Security Holders.

 

There were no matters submitted to a vote of security holders during the fourth quarter of 2002.

 

16



 

Executive Officers of the Registrant

 

The following table sets forth certain information, as of March 11, 2003, with respect to the executive officers of the Registrant.

 

Name

 

Age

 

Position

 

 

 

 

 

 

 

Charles D. Davidson(1)

 

53

 

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

 

 

 

 

 

 

 

Alan R. Bullington(2)

 

51

 

Vice President, International

 

 

 

 

 

 

 

Robert K. Burleson(3)

 

45

 

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

 

 

 

 

 

 

 

Susan M. Cunningham(4)

 

47

 

Senior Vice President, Exploration

 

 

 

 

 

 

 

Albert D. Hoppe(5)

 

58

 

Senior Vice President, General Counsel and Secretary

 

 

 

 

 

 

 

James L. McElvany(6)

 

49

 

Senior Vice President, Chief Financial Officer and Treasurer

 

 

 

 

 

 

 

Richard A. Peneguy, Jr.(7)

 

52

 

Vice President, Offshore

 

 

 

 

 

 

 

William A. Poillion, Jr.(8)

 

53

 

Senior Vice President, Production and Drilling

 

 

 

 

 

 

 

Ted A. Price(9)

 

43

 

Vice President, Onshore

 

 

 

 

 

 

 

David L. Stover(10)

 

45

 

Vice President, Business Development

 

 

 

 

 

 

 

Kenneth P. Wiley(11)

 

50

 

Vice President, Information Systems

 

 


(1)          Charles D. Davidson has served as President and Chief Executive Officer of the Company since October 2000 and Chairman of the Board since April 2001. Prior to October 2000, he served as President and Chief Executive Officer of Vastar Resources, Inc. (“Vastar”) from March 1997 to September 2000 (Chairman from April 2000) and was a Vastar Director from March 1994 to September 2000. From September 1993 to March 1997, he served as a Senior Vice President of Vastar. From December 1992 to October 1993, he was Senior Vice President of the Eastern District for ARCO Oil and Gas Company. From 1988 to December 1992, he held various positions with ARCO Alaska, Inc. Mr. Davidson, age 53, joined ARCO in 1972.

 

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

 

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

 

17



 

with the Company, he was employed by Reliant Energy as Director of Business Development for its interstate pipeline, Reliant Gas Transmission.

 

(4)          Susan M. Cunningham has served as the Company’s Senior Vice President of Exploration since April 2001. In this role, she oversees the Company’s worldwide exploration activities. Prior to joining the Company, Ms. Cunningham was Texaco’s Vice President of worldwide exploration from April 2000 to March 2001. From 1997 through 1999, she was employed by Statoil, beginning in 1997 as Exploration Manager for deepwater Gulf of Mexico, being appointed a Vice President in 1998 and responsible, in 1999, for Statoil’s West Africa exploration efforts.

 

(5)          Albert D. Hoppe has served as Senior Vice President, General Counsel and Secretary of the Company since December 2000. Prior thereto, he served as Vice President, General Counsel and Secretary of Vastar Resources, Inc. from 1994 through 2000. Prior to his Vastar service, he held various executive and management legal positions with Atlantic Richfield Company.

 

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

 

(7)          Richard A. Peneguy, Jr. was elected a Vice President of the Company on April 24, 2001 and has served as Vice President and General Manager, Offshore Division of Samedan Oil Corporation since February 2002. Prior thereto, he served as Vice President and General Manager, Onshore Division of Samedan since January 2000. Prior thereto, he served as General Manager, Onshore Division of Samedan since January 1, 1991.

 

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

 

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

 

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

 

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

 

Officers serve until the next annual organizational meeting of the Board of Directors or until their successors are chosen and qualified. No officer or executive officer of the Registrant currently has an employment agreement with the Registrant or any of its subsidiaries, although Mr. Davidson had an employment agreement with the Registrant until February 1, 2002. There are no family relationships among any of the Registrant’s officers.

 

18



 

PART II

 

Item 5.    Market for Registrant’s Common Equity and Related Stockholder Matters.

 

Common Stock. The Registrant’s Common Stock, $3.33 1/3 par value (“Common Stock”), is listed and traded on the New York Stock Exchange under the symbol “NBL.” The declaration and payment of dividends are at the discretion of the Board of Directors of the Registrant and the amount thereof will depend on the Registrant’s results of operations, financial condition, contractual restrictions, cash requirements, future prospects and other factors deemed relevant by the Board of Directors.

 

Stock Prices and Dividends by Quarters. The following table sets forth, for the periods indicated, the high and low sales price per share of Common Stock on the New York Stock Exchange and quarterly dividends paid per share.

 

 

 

High

 

Low

 

Dividends
Per Share

 

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

 

2001

 

 

 

 

 

 

 

First quarter

 

$

51.09

 

$

39.63

 

$

.04

 

Second quarter

 

$

45.20

 

$

34.26

 

$

.04

 

Third quarter

 

$

38.19

 

$

27.50

 

$

.04

 

Fourth quarter

 

$

40.00

 

$

30.00

 

$

.04

 

 

Transfer Agent and Registrar. The transfer agent and registrar for the Common Stock is Wachovia Bank, N.A., NC1153, 1525 West W. T. Harris Blvd., 3C3, Charlotte, North Carolina 28262-1153.

 

Stockholders’ Profile. As of December 31, 2002, the number of holders of record of Common Stock was 1,085. The following chart indicates the common stockholders by category.

 

December 31, 2002
 
Shares
Outstanding
 

Individuals

 

602,640

 

Joint accounts

 

55,350

 

Fiduciaries

 

221,479

 

Institutions

 

2,551,728

 

Nominees

 

53,922,073

 

Foreign

 

9,275

 

Total-Excluding Treasury Shares

 

57,362,545

 

 

Sales of Unregistered Securities. Prior to January 2002, AMCCO was a 50 percent owned joint venture that owned an indirect 90 percent interest in AMPCO, which completed construction of a methanol plant in Equatorial Guinea in the second quarter of 2001. During 1999, AMCCO issued $125 million Series A-1 and $125 million Series A-2 senior secured notes due December 15, 2004 to fund the remaining construction payments. On January 2, 2002, the Company’s partner in AMCCO directed AMCCO to sell 50 percent of its interest in AMPCO as a component of the partner’s sale of its Equatorial Guinea assets. The proceeds of the AMPCO sale were used to repay in full AMCCO’s $125 million Series A-1 Notes on January 28, 2002 and to make a distribution to the Company’s partner. Since the Company’s partner in AMCCO no longer retains an economic interest in AMPCO, the Company began consolidating

 

19



 

AMCCO’s debt in 2002, thereby including the $125 million Series A-2 Notes in the Company’s balance sheet effective January 28, 2002. The terms of the $125 million Series A-2 Notes remain unchanged. The plant construction started during 1998 and initial production of commercial grade methanol commenced May 2, 2001. At the same time the Series A-2 Notes were issued, the Company guaranteed the payment of interest on the Series A-2 Notes and issued, in a private placement pursuant to Section 4(2) of the Securities Act, 125,000 shares of its Series B Mandatorily Convertible Preferred Stock (the “Series B Preferred”), par value $1.00 per share to Noble Share Trust, which is a Delaware statutory business trust, in exchange for all of the beneficial ownership interests in the Noble Share Trust.

 

Noble Share Trust holds the 125,000 shares of Series B Preferred for the benefit of the holders of the Series A-2 Notes. The Series A-2 indenture trustee, and the holders of 25 percent of the outstanding principal amount of the Series A-2 Notes, would have the right to require a public offering of the Series B Preferred to generate proceeds sufficient to repay the Series A-2 Notes, upon the occurrence of certain events (“Trigger Dates”), including (i) defaults under the Indenture governing the Series A-2 Notes, (ii) a default and acceleration of the Company’s debt exceeding five percent of the Company’s consolidated net tangible assets, and (iii) the simultaneous occurrence of a downgrade of the Company’s unsecured senior debt rating to “Ba1” or below by Moody’s or “BB+” or below by Standard & Poor’s and a decline in the closing price of the Company’s common stock for three consecutive trading days to below $17.50. The exercise of this mandatory remarketing right is subject to certain forbearance provisions that would allow the Company the opportunity to obtain funds for the repayment of the Series A-2 Notes by alternative means for a specified period of time.

 

The terms of the Series B Preferred, including dividend and conversion features, would be reset at the time of the remarketing, based on the recommendation of Credit Suisse First Boston, as Remarketing Agent, as to the terms necessary to generate proceeds to repay the Series A-2 Notes. If the Remarketing Agent is not able to complete a registered public offering of the Series B Preferred, it may under certain circumstances conduct a private placement of such stock. If it were impossible for legal reasons to remarket the Series B Preferred, the Company would be obligated to repay the Series A-2 Notes.

 

The Series B Preferred stock would be mandatorily convertible into the Company’s common stock three years after remarketing (or failed remarketing). Generally, each share of Series B Preferred would then be mandatorily convertible at the “Mandatory Conversion Rate,” which is equal to the following number of shares of the Company’s common stock:

 

(a)   if the Mandatory Conversion Date Market Price is greater than or equal to the Threshold Appreciation Price, the quotient of (i) $1,000 divided by (ii) the Threshold Appreciation Price;

 

(b)   if the Mandatory Conversion Date Market Price is less than the Threshold Appreciation Price but is greater than the Reset Price, the quotient of $1,000 divided by the Mandatory Conversion Date Market Price; and

 

(c)   if the Mandatory Conversion Date Market Price is less than or equal to the Reset Price, the quotient of $1,000 divided by the Reset Price.

 

“Mandatory Conversion Date Market Price” means the average closing price per share of the Company’s common stock for the 20 consecutive trading days immediately prior to, but not including, the mandatory conversion date.

 

“Threshold Appreciation Price” means the product of (i) the Reset Price (as the same may be adjusted from time to time) and (ii) 110 percent.

 

“Reset Price” means the higher of (i) the closing price of a share of the Company’s common stock on the Trigger Date or (ii) the quotient (rounded up to the nearest cent) of $125,000,000 divided by the number, as of the Trigger Date, of

 

20



 

the authorized but unissued shares of common stock that have not been reserved as of the Trigger Date by the Company’s Board of Directors for other purposes.

 

In addition to the mandatory conversion discussed above, each share of the Series B Preferred is generally convertible, at the option of the holder thereof at any time before the mandatory conversion date, into 36.364 shares of the Company’s common stock (the “Optional Conversion Rate”); provided, however, that the Optional Conversion Rate shall adjust, as of the earlier to occur of remarketing or failed remarketing, to the quotient of (i) $1,000 divided by (ii) the Threshold Appreciation Price.

 

21



 

Item 6.    Selected Financial Data.

 

 

 

Year Ended December 31,

 

(in thousands, except per share amounts and ratios)

 

2002

 

2001

 

2000

 

1999

 

1998

 

Revenues and Income

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

1,443,728

 

$

1,588,690

 

$

1,399,457

 

$

918,349

 

$

906,787

 

Net cash provided by operating activities

 

504,291

 

635,772

 

570,334

 

343,100

 

382,010

 

Net income (loss)

 

17,652

 

133,575

 

191,597

 

49,461

 

(164,025

)

Per Share Data

 

 

 

 

 

 

 

 

 

 

 

Basic earnings (loss) per share

 

$

.31

 

$

2.36

 

$

3.42

 

$

.87

 

$

(2.88

)

Cash dividends

 

$

.16

 

$

.16

 

$

.16

 

$

.16

 

$

.16

 

Year-end stock price

 

$

37.55

 

$

35.29

 

$

46.00

 

$

21.44

 

$

24.63

 

Basic weighted average shares outstanding

 

57,196

 

56,549

 

55,999

 

57,005

 

56,955

 

Financial Position (at year end)

 

 

 

 

 

 

 

 

 

 

 

Property, plant and equipment, net:

 

 

 

 

 

 

 

 

 

 

 

Oil and gas mineral interests, equipment and facilities

 

$

2,139,785

 

$

1,953,211

 

$

1,485,123

 

$

1,242,370

 

$

1,429,667

 

Total assets

 

2,730,015

 

2,479,848

 

1,879,280

 

1,420,351

 

1,686,080

 

Long-term obligations:

 

 

 

 

 

 

 

 

 

 

 

Long-term debt, net of current portion

 

977,116

 

837,177

 

525,494

 

445,319

 

745,143

 

Deferred income taxes

 

201,939

 

176,259

 

117,048

 

83,075

 

106,823

 

Other

 

69,820

 

75,629

 

61,639

 

53,877

 

52,868

 

Shareholders’ equity

 

1,009,386

 

1,010,198

 

849,682

 

683,609

 

642,080

 

Ratio of debt-to-book capital

 

.50

 

.47

 

.38

 

.39

 

.54

 

Capital Expenditures

 

 

 

 

 

 

 

 

 

 

 

Oil and gas mineral interests, equipment and facilities

 

$

543,967

 

$

765,291

 

$

502,430

 

$

121,077

 

$

445,910

 

Methanol and power projects

 

57,646

 

95,716

 

98,737

 

89,728

 

25,131

 

Other

 

3,185

 

1,932

 

4,430

 

1,410

 

2,733

 

Total capital expenditures

 

$

604,798

 

$

862,939

 

$

605,597

 

$

212,215

 

$

473,774

 

 

 

For additional information, see “Item 8. Financial Statements and Supplementary Data” of this Form 10-K.

 

Operating Statistics

 

 

 

 

Year Ended December 31,

 

 

 

2002

 

2001

 

2000

 

1999

 

1998

 

Natural Gas

 

 

 

 

 

 

 

 

 

 

 

Sales (in millions)

 

$

392.1

 

$

595.4

 

$

553.7

 

$

365.1

 

$

446.0

 

Production (MMcfpd)

 

387.6

 

422.4

 

406.3

 

455.1

 

566.6

 

Average realized price (per Mcf)

 

$

2.92

 

$

3.98

 

$

3.80

 

$

2.26

 

$

2.20

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil

 

 

 

 

 

 

 

 

 

 

 

Sales (in millions)

 

$

292.9

 

$

255.5

 

$

229.6

 

$

180.6

 

$

160.6

 

Production (Bopd)

 

34,037

 

30,661

 

25,805

 

30,003

 

37,217

 

Average realized price (per Bbl)

 

$

23.98

 

$

23.30

 

$

24.95

 

$

16.81

 

$

12.12

 

 

 

 

 

 

 

 

 

 

 

 

 

Royalty sales (in millions)

 

$

15.6

 

$

20.9

 

$

17.3

 

$

14.0

 

$

13.1

 

 

22



 

Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

This Annual Report on Form 10-K and the documents incorporated herein by reference contain forward-looking statements based on expectations, estimates and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties and assumptions and are influenced by various factors. As a consequence, actual results may differ materially from those expressed in the forward-looking statements. For more information, see “Item 7a. Quantitative and Qualitative Disclosures About Market Risk - Cautionary Statement for Purposes of the Private Securities Litigation Reform Act of 1995 and Other Federal Securities Laws” of this Form 10-K.

 

CRITICAL ACCOUNTING POLICIES AND PRACTICES

 

The preparation of the consolidated financial statements requires management of the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. The Company’s estimates of crude oil and natural gas reserves are the most significant. All of the reserve data in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved natural gas and crude oil reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered.

 

The Company accounts for its crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties are amortized to operations by the unit-of-production method based on proved developed crude oil and natural gas reserves on a property-by-property basis as estimated by Company engineers. Through December 31, 2002, estimated future restoration and abandonment costs are recorded by charges to depreciation, depletion and amortization (“DD&A”) expense over the productive lives of the related properties.

 

The Company generally recognizes revenue when the product is delivered to a third-party purchaser. The Company follows the entitlements method of accounting for its natural gas imbalances. Natural gas imbalances occur when the Company sells more or less natural gas than it is entitled to under its ownership percentage of total natural gas production. Any excess amount received above the Company’s share is treated as a liability. If less than the Company’s entitlement is received, the underproduction is recorded as a receivable.

 

The Company, directly or through its subsidiaries, from time to time, uses various derivative arrangements in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such arrangements include fixed price hedges, costless collars and other contractual arrangements. The Company accounts for its derivative arrangements under Statement of Financial Accounting Standard (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and has elected to designate its derivative arrangements as cash flow hedges.

 

Other significant items subject to estimates and assumptions include the carrying amount of property, plant and equipment; valuation allowances for receivables, inventories and deferred income tax assets; environmental liabilities; valuation of derivative instruments; and assets and obligations related to employee benefits. Actual results could differ from those estimates. Management believes it is necessary to understand the Company’s significant accounting policies, “Item 8. Financial Statements and Supplementary Data—Note 1 - Summary of Significant Accounting Policies” of this Form 10-K, in order to understand the Company’s financial condition, changes in financial condition and results of operations.

 

23



 

 

LIQUIDITY AND CAPITAL RESOURCES

 

Liquidity

 

The Company’s net cash provided from operations in 2002 was lower than 2001 due to lower natural gas prices and decreased gas production volumes, offset partially by higher oil prices and increased oil production volumes. Net cash from operating activities per BOE of production and per share are shown in the charts below.

 

 

 

The crude oil price received by the Company in 2002 increased three percent from 2001 and the natural gas price received by the Company decreased 27 percent in 2002 from the price received in 2001. In 2001, the Company’s crude oil price decreased nine percent and the natural gas price increased five percent compared to 2000.

 

Prior to January 2002, AMCCO was a 50 percent owned joint venture that owned an indirect 90 percent interest in AMPCO, which completed construction of a methanol plant in Equatorial Guinea in the second quarter of 2001. During 1999, AMCCO issued $125 million Series A-1 and $125 million Series A-2 senior secured notes due December 15, 2004 to fund the remaining construction payments. On January 2, 2002, the Company’s partner in AMCCO directed AMCCO to sell 50 percent of its interest in AMPCO as a component of the partner’s sale of its Equatorial Guinea assets. The proceeds of the AMPCO sale were used to repay in full AMCCO’s $125 million Series A-1 Notes on January 28, 2002 and to make a distribution to the Company’s partner. Since the Company’s partner in AMCCO no longer retains an economic interest in AMPCO, the Company began consolidating AMCCO’s debt in 2002, thereby including the $125 million Series A-2 Notes in the Company’s balance sheet effective January 28, 2002. The terms of the $125 million Series A-2 Notes remain unchanged. The plant construction started during 1998 and initial production of commercial grade methanol commenced May 2, 2001. The total costs of the plant and supporting facilities as of December 31, 2002 were $417 million, with the Company responsible for $208.5 million. During 2002, the Company recorded costs of $7 million toward the project.

 

During 2002, $544 million was spent on acquisition, exploration and development projects, $7 million on the methanol project, $51 million on the Machala power project in Ecuador and $3 million for various other projects for total expenditures of $605 million. The 2003 capital expenditures budget is approximately $510 million.

 

The Company’s current ratio (current assets divided by current liabilities) was .66:1 at December 31, 2002, compared with .92:1 at December 31, 2001. The decrease in the current ratio was due to a $57.8 million decrease in cash and short-term investments coupled with an $81.8 million increase in accounts payable.

 

24



 

Financing

 

The Company’s total long-term debt, net of unamortized discount, at December 31, 2002, was $977 million compared to $837 million at December 31, 2001. If the $125 million AMCCO debt had been included, the total long-term debt would have been $962 million at December 31, 2001. The ratio of debt-to-book capital (defined as the Company’s total debt plus its equity) was 50 percent at December 31, 2002, compared with 47 percent at December 31, 2001.

 

(in thousands)

 

Payments Due by Period

 

Contractual
Obligations

 

Total

 

Less Than
1 Year

 

1 to 3
Years

 

4 to 5
Years

 

After 5
Years

 

Long-term debt

 

$

1,025,246

 

$

41,919

 

$

153,327

 

$

380,000

 

$

450,000

 

Drilling obligations

 

118,211

 

116,411

 

1,800

 

 

 

 

 

Total contractual cash obligations

 

$

1,143,457

 

$

158,330

 

$

155,127

 

$

380,000

 

$

450,000

 

 

The Company’s long-term debt, net of current portion, is comprised of:

 

                    $250 million of 8% Senior Notes Due 2027

                    $100 million of 7 1/4% Notes Due 2097

                    $100 million of 7 1/4% Notes Due 2023

                    $380 million on the $400 million credit facility based upon a Eurodollar rate plus a range of 60 to 145 basis points depending upon the percentage of utilization and credit rating, maturing in 2006. The interest rate at December 31, 2002 was 2.47 percent. The interest rate at December 31, 2001 was 3.0 percent.

                    $125 million of 8.95% Series A-2 Notes on the AMCCO debt, payable in 2004. There was no AMCCO debt on the Company’s balance sheet at December 31, 2001.

                    $20.4 million on the Israel debt based upon the London Interbank Offering Rate (“LIBOR”) plus 75 basis points, payable in 2004. The interest rate at December 31, 2002 was 2.18 percent. There was no outstanding Israel debt at December 31, 2001.

                    $7.9 million of the 6.25% Aspect acquisition note, payable in 2004

                    ($6.2) million unamortized discount

 

The Company entered into a new $400 million five-year credit agreement on November 30, 2001 with certain commercial lending institutions which exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. The interest rate is based upon a Eurodollar rate plus a range of 60 to 145 basis points depending upon the percentage of utilization and credit rating. At December 31, 2002, there was $380 million borrowed against this credit agreement, which has a maturity date of November 30, 2006. For more information, see “Item 8. Financial Statements and Supplementary Data—Note 3 - Debt” of this Form 10-K.

 

The Company also entered into a new $200 million 364-day credit agreement on November 27, 2002 with certain commercial lending institutions which exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. The interest rate is based upon a Eurodollar rate plus a range of 62.5 to 150 basis points depending upon the percentage of utilization and credit rating. At December 31, 2002, there were no amounts outstanding under this credit agreement. The agreement has a maturity date of November 26, 2003 for the revolving commitment and a maturity date of November 25, 2004 for the term commitment that includes any balance remaining after the revolving commitment matures. For more information, see “Item 8. Financial Statements and Supplementary Data—Note 3 - Debt” of this Form 10-K.

 

Financial covenants on both the $400 million and $200 million credit facilities include the following: (a) the ratio of Earnings Before Interest, Taxes, Depreciation and Exploration Expense (“EBITDAX”) to total interest expense for any consecutive period of four fiscal quarters ending on the last day of a fiscal quarter may not be less than 4.0 to 1.0; (b) the total debt to capitalization ratio, expressed as a percentage, may not exceed 60 percent at any time; and (c) the total asset value of the Company’s restricted subsidiaries may not be less than $800 million at any time.

 

25



 

The Company had no short-term borrowings outstanding on December 31, 2002. The Company had a $25 million short-term note payable outstanding December 31, 2001, which was repaid January 28, 2002. The note was an uncommitted facility with an interest rate of 3.25 percent for the period December 28, 2001 to January 28, 2002.

 

On January 2, 2002, the Company’s partner in AMCCO directed AMCCO to sell 50 percent of its interest in AMPCO as a component of the partner’s sale of its Equatorial Guinea assets. The proceeds of the AMPCO sale were used to repay in full AMCCO’s $125 million Series A-1 Notes on January 28, 2002 and to make a distribution to the Company’s partner. Since the Company’s partner in AMCCO no longer retains an economic interest in AMPCO, the Company began consolidating AMCCO’s debt in 2002, thereby including the $125 million Series A-2 Notes in the Company’s balance sheet effective January 28, 2002. The terms of the $125 million Series A-2 Notes remain unchanged.

 

Other

 

The Company has paid quarterly cash dividends of $.04 per share since 1989 and currently anticipates it will continue to pay quarterly dividends of $.04 per share.

 

The Company’s Board of Directors, in February 2000, authorized a repurchase of up to $50 million in the Company’s common stock. In the first quarter of 2000, the Company repurchased approximately $30 million of common stock. The 2000 repurchase of 1,386,400 shares at an average cost of $21.84 per share was funded from the Company’s current cash flow. On September 17, 2001 the Company’s Board of Directors approved an expansion of the original repurchase program from $50 million to $100 million. During the fourth quarter of 2001, in conjunction with the expanded repurchase program, the Board approved a stock repurchase forward program. Under the stock repurchase forward program, one of the Company’s banks purchased approximately $35 million of the Company’s stock or 1,044,454 shares on the open market during the first quarter of 2002.

 

The program was scheduled to mature in January 2003 but has been extended to January 2004. Under the provisions of the agreement with the bank, the Company can choose to either purchase the shares from the bank, issue additional shares to the bank to the extent that the share price has decreased, pay the bank a net amount of cash to the extent that the share price has decreased, or receive from the bank a net amount of cash to the extent that the share price has increased. The bank has the right to terminate the agreement prior to the maturity date if the Company’s share price decreases by 50 percent (to $16.77 per share) or if the Company’s credit rating is downgraded below BBB- (S&P) or Baa3 (Moody’s). If either event occurs and the bank exercises its right to terminate, the Company still retains the right to settle in cash or additional shares. The agreement limits the number of shares to be issued by the Company to 14,000,000 additional shares. Amounts paid or received related to the change in share price will be an addition or reduction to the Company’s capital in excess of par value. No settlements have occurred to date. As of December 31, 2002, the fair value of the Company’s obligation under the contract would be an obligation to pay approximately $36.1 million to the bank (and hold the shares as treasury stock), or the bank would return 81,946 shares of Company stock to the Company, or the bank would pay $3.1 million to the Company.

 

The Company has sold a number of non-strategic crude oil and natural gas properties over the past three years. Total amounts of crude oil and natural gas reserves associated with the 2002 and 2000 dispositions were .7 MMBbls of oil and 20.3 Bcf of gas and 1.2 MMBbls of oil and 4.8 Bcf of gas, respectively. There were no significant sales of oil or gas properties in 2001. The Company believes the disposition of non-strategic properties furthers the goal of concentrating its efforts on strategic properties.

 

During 2002, the Company paid $7 million related to certain operating contingencies that had previously been accrued.

 

The Financial Accounting Standards Board (“FASB”) issued SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” in June 1998. The Statement established accounting and reporting standards requiring every derivative instrument (including certain derivative instruments embedded in other contracts) to be recorded in the

 

26



 

balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met wherein gains and losses are reflected in shareholders’ equity as other comprehensive income until the hedged item is recognized. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations, and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting. The Company adopted SFAS No. 133 effective January 1, 2001. The adoption of this statement did not have a material impact on the Company’s results of operations or financial position.

 

RESULTS OF OPERATIONS

 

Net Income and Revenues

 

The Company’s net income for 2002 was $17.7 million, a decrease of $115.9 million from 2001. The decrease was due primarily to a $208.3 million decrease in natural gas sales, offset by a $37.1 million increase in crude oil sales. The decrease in net income for 2001 compared to 2000 was due to a $61.2 million increase in dry hole expense, offset by a $3.8 million decrease in abandoned asset expense.

 

Natural Gas Information

 

Natural gas revenues decreased 34 percent in 2002 due to a 27 percent decrease in the average natural gas price coupled with an eight percent decrease in natural gas production. In the United States, natural gas production decreased 13 percent due to reduced drilling activity, natural decline rates for properties in the Gulf of Mexico and the onshore Gulf Coast region, as well as temporary shut-ins related to Hurricanes Isidore and Lili, coupled with a 25 percent decrease in the average natural gas price. In the North Sea, natural gas revenues decreased 15 percent due to an 11 percent decrease in the average natural gas price coupled with a five percent decrease in natural gas production. In Equatorial Guinea, natural gas revenues increased 39 percent due to the full year of operations of the methanol plant.

 

Natural gas revenues for 2001 increased eight percent due to a four percent increase in natural gas production coupled with a five percent increase in the average natural gas price compared to 2000. The methanol plant in Equatorial Guinea began operations on May 2, 2001, which accounted for the increased natural gas production compared to 2000.

 

The table below depicts average daily natural gas production in Mcf by area for the last three years.

 

 

 

2002

 

2001

 

2000

 

United States

 

327,451

 

378,475

 

378,101

 

North Sea

 

16,991

 

17,830

 

23,676

 

Equatorial Guinea

 

34,382

 

24,488

 

2,572

 

Other International

 

8,799

 

1,651

 

1,970

 

Total

 

387,623

 

422,444

 

406,319

 

 

Natural gas production during 2002 ranged from a low of 351.8 MMcfpd in May, to a high of 424.3 MMcfpd in January. Natural gas accounted for 57 percent of the Company’s total natural gas and crude oil revenues in 2002.

 

27



 

2002 Daily Production by Quarter

 

Natural Gas

 

Crude Oil

 

 

Crude Oil Information

 

Crude oil revenues increased 14 percent during 2002 due to an 11 percent increase in production coupled with a three percent increase in the average crude oil price. In the North Sea, crude oil revenues increased 80 percent due to a full year of production from the Hanze field, the commencement of production from the Hannay field in March 2002 and an eight percent increase in the average crude oil price. In Equatorial Guinea, crude oil revenues increased 18 percent due to a 14 percent increase in production from the Alba field, coupled with a four percent increase in the average crude oil price.

 

Crude oil revenues increased 11 percent in 2001, compared to 2000, due to a 19 percent increase in production offset by a seven percent decline in the average price received for 2001. In the North Sea, crude oil revenues increased 136 percent due to the commencement of production from the Hanze field in August 2001, offset by a 10 percent decrease in the average crude oil price. In Equatorial Guinea, crude oil revenues increased 52 percent due to an 85 percent increase in production from the Alba field, offset by a 17 percent decline in the average price.

 

The table below depicts average daily crude oil production in Bbls by area for the last three years.

 

 

 

2002

 

2001

 

2000

 

United States

 

18,110

 

18,614

 

19,019

 

North Sea

 

7,847

 

4,688

 

1,787

 

Equatorial Guinea

 

5,259

 

4,620

 

2,497

 

Other International

 

2,821

 

2,739

 

2,502

 

Total

 

34,037

 

30,661

 

25,805

 

 

Crude oil production during 2002 ranged from a low of 31,060 Bopd in July, to a high of 36,381 Bopd in April. Crude oil accounted for 43 percent of the Company’s total natural gas and crude oil revenues in 2002.

 

Derivatives and Hedging Activities

 

The Company, directly or through its subsidiaries, from time to time, uses various hedging arrangements in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such arrangements include fixed price hedges, costless collars and other contractual arrangements. Although these hedging arrangements expose the Company to credit risk, the Company monitors the creditworthiness of its counterparties and believes that losses from nonperformance are unlikely to occur. Hedging gains and losses related to the Company’s

 

28



 

crude oil and natural gas production are recorded in crude oil and natural gas sales and royalties. For more information, see “Item 7a. Quantitative and Qualitative Disclosures About Market Risk” of this Form 10-K.

 

Costs and Expenses

 

Crude oil and natural gas operations expense, consisting of lease operating expense, workover expenses, production taxes and other related lifting costs, was flat overall, in absolute dollars, in 2002 compared to 2001. In the North Sea, operations expense increased 78 percent due to a full year of production operations from the Hanze field and the commencement of operations from the Hannay field in March 2002. In Equatorial Guinea, operations expense increased 45 percent due to the increased production from the Alba field. Domestic operations expense decreased in absolute terms during 2002 offsetting the international increases. Crude oil and natural gas operations expense increased 10 percent overall in 2001 from 2000. In the North Sea, operations expense increased 16 percent due to the commencement of operations of the Hanze field in August 2001. In Equatorial Guinea, operations expense increased 61 percent due to the commencement of natural gas deliveries to the methanol plant in May 2001. Included in operations expense were workover costs of $8.5 million, $15.1 million and $21.1 million for 2002, 2001 and 2000, respectively. The workovers increased operations expense in such periods by $.04, $.07 and $.10 per Mcfe, respectively.

 

 

In 2002, DD&A expense increased slightly compared to 2001. In the North Sea, DD&A expense increased 71 percent due to a full year’s production of the Hanze field. In Equatorial Guinea, DD&A expense increased 50 percent due to the results of the field expansion, which included a full year of natural gas sales to the methanol plant. The unit rate of DD&A per BOE was $7.92 in 2002.

 

In 2001, DD&A expense increased 23 percent overall compared to 2000. In the United States, DD&A expense increased 22 percent due to increased development costs incurred in the Gulf of Mexico to stabilize production volumes. In the North Sea, DD&A expense increased 34 percent due to the commencement of production from the Hanze field in August 2001. In Equatorial Guinea, DD&A expense increased 186 percent due to the commencement of natural gas sales to the methanol plant in May 2001. The unit rate of DD&A per BOE was $7.70 in 2001.

 

Through December 31, 2002, the Company provided for the cost of future liabilities related to restoration and dismantlement costs for offshore facilities. This provision is based on the Company’s best estimate of such costs to be incurred in future years based on information from the Company’s engineers. These estimated costs were provided through charging DD&A expense using a ratio of production divided by reserves multiplied by the estimated costs to dismantle and restore. The Company adopted SFAS No. 143 on January 1, 2003 and will recognize, as the fair value of asset retirement obligations, $99.7 million related to the United States and $10.0 million related to the North Sea. The Company’s accumulated provision for future dismantlement and restoration cost was $84.1 million at

 

29



 

December 31, 2002, $80.0 million at December 31, 2001 and $79.7 million at December 31, 2000. The Company has not determined the cumulative effect of adoption of this standard. Total estimated future dismantlement and restoration costs of $206.6 million, which consists of $188.7 million for the United States and $17.9 million for the North Sea, are included in future production and development costs for purposes of estimating the future net revenues relating to the Company’s proved reserves. For more information, see “Item 8. Financial Statements and Supplementary Data—Note 1 - Summary of Significant Accounting Policies” of this Form 10-K.

 

Crude oil and natural gas exploration expense consists of dry hole expense, unproved lease amortization, seismic and other miscellaneous exploration expense, including lease rentals and exploration staff. The table below depicts the exploration expense by area for the last three years.

 

(in thousands)

 

2002

 

2001

 

2000

 

United States

 

 

 

 

 

 

 

Dry hole expense

 

$

64,449

 

$

54,810

 

$

37,281

 

Unproved lease amortization

 

19,426

 

15,112

 

15,675

 

Seismic

 

14,282

 

13,328

 

17,794

 

Other

 

22,538

 

17,242

 

9,617

 

United States Total Exploration Expense

 

$

120,695

 

$

100,492

 

$

80,367

 

North Sea

 

 

 

 

 

 

 

Dry hole expense

 

$

544

 

$

28,992

 

$

17

 

Unproved lease amortization

 

178

 

1,725

 

 

 

Seismic

 

827

 

2,209

 

239

 

Other

 

3,661

 

2,024

 

1,140

 

North Sea Total Exploration Expense

 

$

5,210

 

$

34,950

 

$

1,396

 

Other International including Israel and Equatorial Guinea

 

 

 

 

 

 

 

Dry hole expense

 

$

16,403

 

$

15,882

 

$

1,165

 

Unproved lease amortization

 

1,650

 

376

 

400

 

Seismic

 

5,383

 

70

 

705

 

Other

 

1,360

 

326

 

835

 

Other International Total Exploration Expense

 

$

24,796

 

$

16,654

 

$

3,105

 

Total Exploration Expense

 

$

150,701

 

$

152,096

 

$

84,868

 

 

Impairment of Operating Assets

 

Developed crude oil and natural gas properties and other long-lived assets are assessed whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. The Company performs this review of recoverability by estimating future cash flows. If the sum of the expected future cash flows is less than the carrying amount of the asset, an impairment is recognized based on the fair value of the assets as determined using the expected present value of future net cash flows. The Company recorded no operating asset impairments during 2002, 2001 or 2000. Individually significant unproved crude oil and natural gas properties are periodically assessed for impairment of value and a loss is recognized at the time of impairment by providing an impairment allowance.

 

Selling, General and Administrative Expenses (“SG&A”)

 

SG&A expenses increased $3.5 million in 2002 compared to 2001 and decreased $3.1 million in 2001 compared to 2000. The increase in SG&A expenses for 2002 is due to increased salary and legal expense, as well as increased costs associated with the Company’s international expansion. The decrease in 2001 compared to 2000 reflects the Company’s effort to reduce SG&A through efficiencies and other reduction measures.

 

30



 

Gathering, Marketing and Processing

 

NEMI markets the majority of the Company’s domestic natural gas, as well as certain third-party natural gas. NEMI sells natural gas directly to end-users, natural gas marketers, industrial users, interstate and intrastate pipelines, power generators and local distribution companies. NEMI markets a portion of the Company’s domestic crude oil, as well as certain third-party crude oil. The Company records all of NEMI’s sales and expenses as gathering, marketing and processing revenues and expenses. All intercompany sales and expenses have been eliminated in the Company’s consolidated financial statements.

 

The gathering, marketing and processing revenues less expenses for NEMI are reflected in the table below.

 

(in thousands)

 

2002

 

2001

 

2000

 

(amounts include inter-
company eliminations)

 

Crude
Oil

 

Natural
Gas

 

Crude
Oil

 

Natural
Gas

 

Crude
Oil

 

Natural
Gas

 

Revenues

 

$

88,377

 

$

625,714

 

$

75,550

 

$

645,400

 

$

91,204

 

$

498,729

 

Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost of goods sold

 

61,553

 

588,022

 

49,191

 

607,170

 

63,005

 

464,600

 

Transportation

 

20,323

 

28,284

 

19,739

 

27,779

 

19,455

 

24,014

 

General and administrative

 

802

 

3,857

 

199

 

3,176

 

190

 

3,002

 

Total Expenses

 

$

82,678

 

$

620,163

 

$

69,129

 

$

638,125

 

$

82,650

 

$

491,616

 

Gross Margin

 

$

5,699

 

$

5,551

 

$

6,421

 

$

7,275

 

$

8,554

 

$

7,113

 

 

The margins for natural gas on a per MMBTU basis were $.035 for 2002 and 2001 and $.027 for 2000. The increase in natural gas margin on a per MMBTU basis for 2001 compared to 2000 was due to the improvement in natural gas prices. The margins for crude oil on a per Bbl basis were $.84 for 2002, $.95 for 2001 and $1.28 for 2000. The decrease in crude oil margin for 2002 compared to 2001 was due to increased general and administrative expenses coupled with higher transportation expense. The decrease in crude oil margin for 2001 compared to 2000 was due to lower crude oil prices.

 

Income Taxes

 

Income tax expense decreased to $25 million in 2002 from $91 million in 2001, primarily from the decrease in income. However, the effective income tax rate increased to 59 percent in 2002 from 41 percent in 2001. During 2002, more of the Company’s income was from international operations. Some of the countries in which the international operations were conducted have a higher statutory income tax rate than the United States. To a lesser extent, also impacting the effective rate in 2002 was the lower income level.

 

FUTURE TRENDS

 

The Company expects crude oil and natural gas production to increase in 2003 and 2004 compared to 2002. The increased production in 2003 is expected primarily from the phase 2A expansion of the Alba field in Equatorial Guinea, the startup of production from the Mari-B field, offshore Israel, production from the CDX block in China and a full year of production in Ecuador. The increase in 2004 is expected primarily from the continued expansion of markets in Israel and the phase 2B expansion of the LPG plant in Equatorial Guinea.

 

The Company recently set its 2003 capital expenditures budget at approximately $510 million. Such expenditures are planned to be funded principally through internally generated cash flows. The Company believes that it has the capital structure to take advantage of strategic acquisitions, as they become available, through internally generated cash flows or available lines of credit and other borrowing opportunities.

 

31



 

SFAS No. 148, “Accounting for Stock-Based Compensation,” was issued in December 2002. This statement amends SFAS No. 123, “Accounting for Stock-Based Compensation,” to provide for alternative methods of transition for an entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation. It also amends the disclosure provisions of that statement to require prominent disclosure about the effects on reported net income of an entity’s accounting policy decisions with respect to stock-based employee compensation.

 

The Company currently accounts for stock-based employee compensation plans under the recognition and measurement principles of the Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.” The Company has not determined if it will adopt the fair value provisions of SFAS No. 123.

 

In June 2002, the Emerging Issues Task Force (“EITF”) reached a consensus on certain issues contained in Topic 02-03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts” under EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” While the Company does not engage in material energy trading activities, the EITF has expanded its definition of energy trading activities to include the marketing activities in which the Company is engaged. As of January 1, 2003, the Company will present its gathering, marketing and processing activities in the statement of operations for all periods on a net rather than a gross basis. The change will significantly decrease reported marketing sales and purchases, but will have no effect on operating income or cash flow.

 

Management believes that the Company is well positioned with its balanced reserves of crude oil and natural gas and downstream projects. The uncertainty of commodity prices continues to affect the crude oil, natural gas and methanol industries. The Company cannot predict the extent to which its revenues will be affected by inflation, government regulation or changing prices.

 

Item  7a.         Quantitative and Qualitative Disclosures About Market Risk.

 

The Company is exposed to market risk in the normal course of its business operations. Management believes that the Company is well positioned with its mix of crude oil and natural gas reserves to take advantage of future price increases that may occur. However, the uncertainty of crude oil and natural gas prices continues to impact the oil and gas industry. Due to the volatility of crude oil and natural gas prices, the Company, from time to time, has used derivative hedging instruments and may do so in the future as a means of managing its exposure to price changes.

 

During 2002, the Company entered into various natural gas costless collars, natural gas costless collar combinations and crude oil costless collar transactions related to its production. The table below depicts the various transactions for 2002.

 

 

 

Natural Gas

 

Hedge MMBTUpd

 

170,274

 

Floor price range

 

$

2.00 - $3.50

 

Ceiling price range

 

$

2.45 - $5.10

 

Percent of daily production

 

44

%

Gain (loss) per Mcf

 

$

.03

 

 

 

 

Crude Oil

 

Hedge Bpd

 

5,247

 

Floor price range

 

$

23.00 - $24.00

 

Ceiling price range

 

$

29.30 - $30.10

 

Percent of daily production

 

15

%

Gain (loss) per Bbl

 

$

0

 

 

32



 

As of December 31, 2002, the Company had entered into costless collars related to its natural gas and crude oil production to support the Company’s investment program as follows:

 

 

 

Natural Gas

 

Crude Oil

 

Production
Period

 

MMBTU
Per Day

 

Price
Per MMBTU
Floor - Ceiling

 

Bbls
Per Day

 

Price
Per Bbl
Floor - Ceiling

 

1Q 2003

 

185,000

 

$

3.87 - $4.82

 

15,000

 

$

23.00 - $28.63

 

2Q 2003

 

185,000

 

$

3.43 - $4.57

 

15,000

 

$

23.00 - $28.63

 

3Q 2003

 

185,000

 

$

3.43 - $4.60

 

10,000

 

$

23.00 - $27.95

 

4Q 2003

 

185,000

 

$

3.43 - $4.84

 

10,000

 

$

23.00 - $27.95

 

 

The contracts entitle the Company (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the last scheduled NYMEX trading day applicable for each calculation period is less than the floor price. The Company would pay the counterparty if the settlement price for the last scheduled NYMEX trading day applicable for each calculation period were more than the ceiling price. The amount payable by the floating price payor, if the floating price is above the ceiling price, is the product of the notional quantity per calculation period and the excess, if any, of the floating price over the ceiling price in respect of each calculation period. The amount payable by the fixed price payor, if the floating price is below the floor price, is the product of the notional quantity per calculation period and the excess, if any, of the floor price over the floating price in respect of each calculation period.

 

During 2001, the Company had natural gas costless collars for the fourth quarter of 2001 for 50,000 MMBTU of natural gas per day, with a floor price of $3.25 per MMBTU and a ceiling price of $4.60 per MMBTU. The net effect of this fourth quarter 2001 hedge was a $.02 per Mcf increase in the average natural gas price for the year 2001. Of the 50,000 MMBTU per day of costless collars, 25,000 MMBTU per day were terminated early, at a gain. As a result, the Company recognized an additional $.70 per MMBTU on the 25,000 MMBTU of natural gas per day in 2001.

 

NEMI, from time to time, employs hedging arrangements in connection with its purchases and sales of production. While most of NEMI’s purchases are made for an index-based price, NEMI’s customers often require prices that are either fixed or related to NYMEX. In order to establish a fixed margin and mitigate the risk of price volatility, NEMI may convert a fixed or NYMEX sale to an index-based sales price (such as by purchasing an index-based futures contract obligating NEMI for delivery of production). Due to the size of such transactions and certain restraints imposed by contract and by Company guidelines, as of December 31, 2002, the Company had no material market risk exposure from NEMI’s hedging activity.

 

The Company has a $400 million credit agreement that exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. The interest rate is based upon a Eurodollar rate plus a range of 60 to 145 basis points depending upon the percentage of utilization and credit rating. At December 31, 2002, there was $380 million borrowed against this credit agreement with an interest rate of 2.47 percent and a maturity date of November 30, 2006. A ten percent change in the December 31, 2002 interest rate on this $380 million would result in a change in interest expense of $937,080. All other significant Company long-term debt is fixed-rate and, therefore, does not expose the Company to the risk of earnings or cash flow loss due to changes in market interest rates. For more information, see “Item 8. Financial Statements and Supplementary Data—Note 3 - Debt” of this Form 10–K.

 

The Company does not enter into foreign currency derivatives. The U.S. dollar is considered the primary currency for each of the Company’s international operations. Transactions that are completed in a foreign currency are translated into U.S. dollars and recorded in the financial statements. Translation gains or losses were not material in any of the periods presented and the Company does not believe it is currently exposed to any material risk of loss on this basis. Such gains or losses are included in other income on the statement of operations. However, certain sales transactions

 

33



 

are concluded in foreign currencies and the Company, therefore, is exposed to potential risk of loss based on fluctuation in exchange rates from time to time.

 

Cautionary Statement for Purposes of the Private Securities Litigation Reform Act of 1995 and Other Federal Securities Laws

 

General. Noble Energy is including the following discussion to generally inform its existing and potential security holders of some of the risks and uncertainties that can affect the Company and to take advantage of the “safe harbor” protection for forward-looking statements afforded under federal securities laws. From time to time, the Company’s management or persons acting on management’s behalf make forward-looking statements to inform existing and potential security holders about the Company. These statements may include, but are not limited to, projections and estimates concerning the timing and success of specific projects and the Company’s future: (1) income, (2) crude oil and natural gas production, (3) crude oil and natural gas reserves and reserve replacement and (4) capital spending. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. Sometimes the Company will specifically describe a statement as being a forward-looking statement. In addition, except for the historical information contained in this Form 10-K, the matters discussed in this Form 10-K are forward-looking statements. These statements by their nature are subject to certain risks, uncertainties and assumptions and will be influenced by various factors. Should any of the assumptions underlying a forward-looking statement prove incorrect, actual results could vary materially.

 

Noble Energy believes the factors discussed below are important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made herein or elsewhere by the Company or on its behalf. The factors listed below are not necessarily all of the important factors. Unpredictable or unknown factors not discussed herein could also have material adverse effects on actual results of matters that are the subject of forward-looking statements. Noble Energy does not intend to update its description of important factors each time a potential important factor arises. The Company advises its stockholders that they should: (1) be aware that important factors not described below could affect the accuracy of our forward-looking statements, and (2) use caution and common sense when analyzing our forward-looking statements in this document or elsewhere. All of such forward-looking statements are qualified in their entirety by this cautionary statement.

 

Volatility and Level of Hydrocarbon Commodity Prices. Historically, natural gas and crude oil prices have been volatile. These prices rise and fall based on changes in market supply and demand fundamentals and changes in the political, regulatory and economic climates and other factors that affect commodities markets generally and are outside of Noble Energy’s control. Some of Noble Energy’s projections and estimates are based on assumptions as to the future prices of natural gas and crude oil. These price assumptions are used for planning purposes. The Company expects its assumptions may change over time and that actual prices in the future may differ from our estimates. Any substantial or extended change in the actual prices of natural gas and/or crude oil could have a material effect on: (1) the Company’s financial position and results of operations, (2) the quantities of natural gas and crude oil reserves that the Company can economically produce, (3) the quantity of estimated proved reserves that may be attributed to its properties, and (4) the Company’s ability to fund its capital program.

 

Production Rates and Reserve Replacement. Projecting future rates of crude oil and natural gas production is inherently imprecise.  Producing crude oil and natural gas reservoirs generally have declining production rates. Production rates depend on a number of factors, including geological, geophysical and engineering issues, weather, production curtailments or restrictions, prices for natural gas and crude oil, available transportation capacity, market demand and the political, economic and regulatory climates. Another factor affecting production rates is Noble Energy’s ability to replace depleting reservoirs with new reserves through exploration success or acquisitions. Exploration success is difficult to predict, particularly over the short term, where results can vary widely from year to year. Moreover, the Company’s ability to replace reserves over an extended period depends not only on the total volumes found, but also on the cost of finding and developing such reserves. Depending on the general price

 

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environment for natural gas and crude oil, Noble Energy’s finding and development costs may not justify the use of resources to explore for and develop such reserves.

 

Reserve Estimates. Noble Energy’s forward-looking statements are predicated, in part, on the Company’s estimates of its crude oil and natural gas reserves. All of the reserve data in this Form 10-K or otherwise made by or on behalf of the Company are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved natural gas and crude oil reserves. Projecting future rates of production and timing of future development expenditures is also inexact. Many factors beyond the Company’s control affect these estimates. In addition, the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Therefore, estimates made by different engineers may vary. The results of drilling, testing and production after the date of an estimate may also require a revision of that estimate, and these revisions may be material. As a result, reserve estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered.

 

Laws and Regulations. Noble Energy’s forward-looking statements are generally based on the assumption that the legal and regulatory environments will remain stable. Changes in the legal and/or regulatory environments could have a material effect on the Company’s future results of operations and financial condition. Noble Energy’s ability to economically produce and sell crude oil, natural gas, methanol and power is affected by a number of legal and regulatory factors, including federal, state and local laws and regulations in the U.S. and laws and regulations of foreign nations, affecting: (1) crude oil and natural gas production, (2) taxes applicable to the Company and/or its production, (3) the amount of crude oil and natural gas available for sale, (4) the availability of adequate pipeline and other transportation and processing facilities, and (5) the marketing of competitive fuels. The Company’s operations are also subject to extensive federal, state and local laws and regulations in the U.S. and laws and regulations of foreign nations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Noble Energy’s forward-looking statements are generally based upon the expectation that the Company will not be required, in the near future, to expend cash to comply with environmental laws and regulations that are material in relation to its total capital expenditures program. However, inasmuch as such laws and regulations are frequently changed, the Company is unable to accurately predict the ultimate financial impact of compliance.

 

Drilling and Operating Risks. Noble Energy’s drilling operations are subject to various risks common in the industry, including cratering, explosions, fires and uncontrollable flows of crude oil, natural gas or well fluids. In addition, a substantial amount of the Company’s operations are currently offshore, domestically and internationally, and subject to the additional hazards of marine operations, such as loop currents, capsizing, collision, and damage or loss from severe weather. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including drilling conditions, pressure or irregularities in formations, equipment failures or accidents and adverse weather conditions.

 

Competition. The Company’s forward-looking statements are generally based on a stable competitive environment. Competition in the industry is intense. Noble Energy actively competes for reserve acquisitions and exploration leases and licenses, for the labor and equipment required to operate and develop crude oil and natural gas properties and in the gathering and marketing of natural gas, crude oil, methanol and power. The Company’s competitors include the major integrated oil companies, independent crude oil and natural gas concerns, individual producers, natural gas and crude oil marketers and major pipeline companies, as well as participants in other industries supplying energy and fuel to industrial, commercial and individual consumers, many of whom have greater financial resources than the Company.

 

Noble Energy believes that the location of its properties, its expertise in exploration, drilling and production operations, the experience of its management and the efforts and expertise of its marketing units generally enable it to compete effectively. In making projections with respect to numerous aspects of the Company’s business, Noble Energy generally assumes that there will be no material adverse change in competitive conditions.

 

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Item  8.          Financial Statements and Supplementary Data.

 

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

Independent Auditors’ Reports

 

 

 

Consolidated Balance Sheets as of December 31, 2002 and 2001

 

 

 

Consolidated Statements of Operations for each of the three years in the period ended December 31, 2002

 

 

 

Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2002

 

 

 

Consolidated Statements of Shareholders’ Equity and Other Comprehensive Income for each of the three years in the period ended December 31, 2002

 

 

 

Notes to Consolidated Financial Statements

 

 

 

Supplemental Oil and Gas Information (Unaudited)

 

 

 

Supplemental Quarterly Financial Information (Unaudited)

 

All other financial statement schedules have been omitted because the required information is not present or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the financial statements, including the notes thereto.

 

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Independent Auditor’s Report

 

To the Shareholders and Board of Directors of Noble Energy, Inc.:

 

We have audited the accompanying consolidated balance sheet of Noble Energy, Inc. (a Delaware corporation) and subsidiaries as of December 31, 2002 and the related consolidated statements of operations, shareholders’ equity and other comprehensive income, and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. The financial statements of the Company as of December 31, 2001 and 2000, and for the two years then ended, were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements dated January 24, 2002.

 

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Noble Energy, Inc. and subsidiaries as of December 31, 2002 and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

 

As discussed above, other auditors who have ceased operations audited the 2001 and 2000 financial statements of Noble Energy, Inc. As described in “Note 11 - Geographical Data,” the Company changed the composition of its reportable segments in 2002, and the amounts in the 2001 and 2000 financial statements relating to reportable segments have been restated to conform to the 2002 composition of reportable segments. We audited the adjustments that were applied to restate the disclosures for reportable segments reflected in the 2001 and 2000 financial statements. In our opinion, such adjustments are appropriate and have been properly applied. However, we were not engaged to audit, review or apply any procedures to the 2001 and 2000 financial statements of Noble Energy, Inc. other than with respect to such adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2001 and 2000 financial statements taken as a whole.

 

 

KPMG LLP

 

 

Houston, Texas

February 21, 2003

 

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