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, 2004

 

 

 

OR

 

 

 

o

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

 

 

For the transition period from      to     

 

Commission file number: 001-07964

 

NOBLE ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

Delaware

 

73-0785597

(State of incorporation)

 

(I.R.S. employer identification number)

 

 

 

100 Glenborough Drive, Suite 100

 

 

Houston, Texas

 

77067

(Address of principal executive offices)

 

(Zip Code)

 

(Registrant’s telephone number, including area code)

(281) 872-3100

 

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

 

Title of Each Class

 

Name of Each Exchange on
Which Registered

 

 

 

 

 

Common Stock, $3.33-1/3 par value

 

New York Stock Exchange, Inc.

 

Preferred Stock Purchase Rights

 

New York Stock Exchange, Inc.

 

 

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes   ý     No   o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ý

 

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

 

Aggregate market value of Common Stock held by nonaffiliates as of June 30, 2004:  $2,590,000,000.

Number of shares of Common Stock outstanding as of February 25, 2005:  59,043,952.

 

DOCUMENT INCORPORATED BY REFERENCE

 

Portions of the Registrant’s definitive proxy statement for the 2005 Annual Meeting of Stockholders to be held on April 26, 2005, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2004, are incorporated by reference into Part III.

 

 



 

TABLE OF CONTENTS

 

 

PART I.

 

 

 

 

Item 1.

Business

 

 

 

 

 

General

 

 

 

 

 

Current Developments

 

 

 

 

 

Crude Oil and Natural Gas

 

 

 

 

 

Exploration, Exploitation and Development Activities

 

 

 

 

 

Production Activities

 

 

 

 

 

Acquisitions of Oil and Gas Properties, Leases and Concessions

 

 

 

 

 

Dispositions of Oil and Gas Properties

 

 

 

 

 

Marketing

 

 

 

 

 

Regulations and Risks

 

 

 

 

 

Competition

 

 

 

 

 

Unconsolidated Subsidiaries

 

 

 

 

 

Geographical Data

 

 

 

 

 

Employees

 

 

 

 

 

Available Information

 

 

 

 

Item 2.

Properties

 

 

 

 

 

Offices

 

 

 

 

 

Crude Oil and Natural Gas

 

 

 

 

Item 3.

Legal Proceedings

 

 

 

 

Item 4.

Submission of Matters to a Vote of Security Holders

 

 

 

 

 

Executive Officers of the Registrant

 

 

 

 

 

PART II.

 

 

 

 

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

 

 

 

Item 5c.

Stock Repurchases

 

 

 

 

Item 6.

Selected Financial Data

 

 

 

 

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

 

 

 

Item 7a.

Quantitative and Qualitative Disclosures About Market Risk

 

 

 

 

Item 8.

Financial Statements and Supplementary Data

 

 

 

 

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

 

 

 

Item 9a.

Controls and Procedures

 

 

 

 

Item 9b.

Other Information

 

 

 

 

 

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.

Principal Accounting Fees and Services

 

 

 

 

 

PART IV.

 

 

 

 

Item 15.

Exhibits

 

 

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PART I

 

Item 1.                                   Business.

 

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

 

General

 

Noble Energy, Inc. (the “Company” or “Noble Energy”), formerly known as Noble Affiliates, Inc., is a Delaware corporation that has been publicly traded on the New York Stock Exchange (“NYSE”) since 1980. Noble Energy has been engaged, directly or through its subsidiaries, in the exploration, production and marketing of crude oil and natural gas since 1932, when Noble Energy’s predecessor, Samedan Oil Corporation (“Samedan”), was organized. Noble Energy was organized in 1969 under the name “Noble Affiliates, Inc.” and was Samedan’s parent entity until Samedan was merged into Noble Energy effective December 31, 2002. The Company is noted for its innovative methods of marketing its international natural gas reserves through projects such as its methanol plant in Equatorial Guinea and its natural gas-to-power project (the “Machala Power Plant”) in Ecuador.

 

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

 

NEMI, a wholly-owned subsidiary, 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.

 

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In this report, the following abbreviations are used:

 

Bbl(s)

 

Barrel(s)

MBbls

 

Thousand barrels

Bpd

 

Barrels per day

Bopd

 

Barrels oil per day

MMBbls

 

Million barrels

MBpd

 

Thousand barrels per day

MMBpd

 

Million barrels per day

MBopd

 

Thousand barrels oil per day

MMBopd

 

Million barrels oil per day

BOE

 

Barrels oil equivalent

Boepd

 

Barrels oil equivalent per day

MMBoe

 

Million barrels oil equivalent

MMBoepd

 

Million barrels oil equivalent per day

$MM

 

Millions of dollars

Kwh

 

Kilowatt hours

MW

 

Megawatt

MWH

 

Megawatt hours

Mcf

 

Thousand cubic feet

Mcfpd

 

Thousand cubic feet per day

Mcfe

 

Thousand cubic feet equivalent

MMcf

 

Million cubic feet

MMcfepd

 

Million cubic feet equivalent per day

MMcfpd

 

Million cubic feet per day

Bcf

 

Billion cubic feet

Bcfe

 

Billion cubic feet equivalent

Bcfepd

 

Billion cubic feet equivalent per day

Bcfpd

 

Billion cubic feet per day

BTU

 

British thermal unit

BTUpcf

 

British thermal unit per cubic foot

MMBTU

 

Million British thermal units

MMBTUpd

 

Million British thermal units per day

MTpd

 

Metric tons per day

LPG

 

Liquefied petroleum gas

LNG

 

Liquefied natural gas

 

For reporting BOE or Mcfe, one Bbl of oil, condensate or LPG is equal to six Mcf of natural gas.

 

Current Developments

 

Pending Merger with Patina Oil & Gas Corporation

 

On December 15, 2004, the Boards of Directors of Noble Energy and Patina Oil & Gas Corporation (“Patina”) approved Noble Energy’s merger (the “Merger Agreement”) with Patina. As a result of the proposed merger, Patina will merge into a wholly-owned subsidiary of Noble Energy, and Patina shareholders will receive aggregate consideration comprised of approximately 60 percent Noble Energy common stock and 40 percent cash. Total consideration for the outstanding shares of Patina is fixed at approximately $1.1 billion in cash and approximately 27 million Noble Energy shares, not including options and warrants exchanged in the transaction, and subject to adjustment as provided in the Merger Agreement. Under the terms of the Merger Agreement, Patina shareholders will have the right to elect to receive either cash or Noble Energy common stock, or a combination thereof, in exchange for their shares of Patina common stock, subject to an allocation mechanism if either the cash election or the stock election is oversubscribed. While the per share consideration was initially set in the Merger Agreement at $37.00 in cash or .6252 shares of Noble Energy common stock, the per share consideration is subject to adjustment upwards or downwards. This adjustment will reflect 37.5126 percent of the difference between $59.18 and the price of Noble Energy’s shares during a specified period prior to closing. In addition, the per share consideration is adjusted so that each Patina share receives consideration representing equal value regardless of whether it is converted into cash or Noble Energy common stock. The proposed merger is subject to the approval of the shareholders of Patina and Noble Energy and other customary conditions. The proposed merger is expected to be completed in the second quarter of 2005.

 

For more information regarding the proposed merger between Noble Energy and Patina, please refer to the joint proxy statement/prospectus of Noble Energy and Patina that is included in the registration statement on Form S-4 filed by Noble Energy with the United States Securities and Exchange Commission (“SEC”) on January 25, 2005. This proxy statement/prospectus contains important information about the proposed merger. These materials are not yet final and will be amended. Investors and security holders of Noble Energy and Patina are urged to read the joint proxy statement/prospectus filed, and any other relevant materials filed by Noble Energy or Patina because they contain, or will contain, important information about Noble Energy, Patina and the proposed merger. The preliminary materials filed on January 25, 2005, the definitive versions of these materials and other relevant materials (when they

 

2



 

become available) and any other documents filed by Noble Energy or Patina with the SEC, may be obtained for free at the SEC’s website at www.sec.gov. In addition, the documents filed with the SEC by Noble Energy may be obtained free of charge from Noble Energy’s website at www.nobleenergyinc.com. The documents filed with the SEC by Patina may be obtained free of charge from Patina’s website at www.patinaoil.com.

 

Crude Oil and Natural Gas

 

Noble Energy is an independent energy company engaged, directly or through its subsidiaries or various arrangements with other companies, in the exploration, development, production and marketing of crude oil and natural gas. Exploration activities include geophysical and geological evaluation and exploratory drilling on properties for which the Company has exploration rights. The Company has exploration, exploitation and production operations domestically and internationally. The domestic areas consist of: offshore in the Gulf of Mexico and California; the Gulf Coast Region (Louisiana and Texas); the Mid-continent Region (Oklahoma and Kansas); and the Rocky Mountain Region (Colorado, Montana, Nevada, Wyoming and California). The international areas of operations include Argentina, China, Ecuador, Equatorial Guinea, the Mediterranean Sea (Israel) and the North Sea (the Netherlands and the United Kingdom). 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 Gulf of Mexico deepwater areas, and away from the Gulf of Mexico’s conventional shallow shelf, in order to take advantage of potentially larger prospect sizes. The Company’s current offshore production is derived from 157 gross wells operated by Noble Energy and 175 gross wells operated by others. At December 31, 2004, the Company held offshore federal leases covering 704,329 gross developed acres and 749,167 gross undeveloped acres on which the Company currently intends to conduct future exploration activities. For more information, see “Item 2.  Properties—Crude Oil and Natural Gas” of this
Form 10-K.

 

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

 

Noble Energy’s current onshore production is derived from 1,396 gross wells operated by the Company and 511 gross wells operated by others. At December 31, 2004, the Company held 645,275 gross developed acres and 352,664 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.

 

Domestic Division. On August 30, 2004, Noble Energy announced that the Company had combined the operations of its U.S. onshore and offshore divisions to create a single domestic division.

 

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. At December 31, 2004, the Company held 113,325 gross developed acres and 2,341,884 gross undeveloped acres in Argentina on which the Company may conduct future exploration activities. For more information, see “Item 2.  Properties—Crude Oil and Natural Gas” of this Form 10-K.

 

China. Noble Energy has been actively engaged in exploration, exploitation and development of crude oil and natural gas properties in China since 1996. The Company has a concession offshore in the southern portion of Bohai Bay. At

 

3



 

December 31, 2004, the Company held 7,413 gross developed acres and no gross undeveloped acres in China. For more information, see “Item 2.  Properties—Crude Oil and Natural Gas” of this Form 10-K.

 

Ecuador. Noble Energy has been actively engaged in exploration, exploitation and development of natural gas properties in Ecuador since 1996. The Company is currently utilizing the natural gas from the Amistad 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. With current generating capacity of 130 MW of electricity, additional capital investment for combined cycle and a third turbine could ultimately increase the power plant’s capacity to generate approximately 300 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 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.

 

Equatorial Guinea. Noble Energy has been actively engaged in exploration, exploitation and development of crude oil and natural gas properties offshore Equatorial Guinea (West Africa) since 1990. Production from the Alba field consists of natural gas and condensate. The majority of the natural gas production is sold to a methanol plant, which began production in the second quarter of 2001. The methanol plant has a contract, which runs through 2026, to purchase natural gas from the Alba field. The plant is owned by Atlantic Methanol Production Company, LLC (“AMPCO”), in which the Company owns a 45 percent interest through its ownership interest in Atlantic Methanol Capital Company (“AMCCO”). For more information on the methanol plant, see “Item 1. Business—Unconsolidated Subsidiaries” of this Form 10-K.

 

In 2004, Noble Energy entered into an additional natural gas contract, which runs through 2023, with an LNG plant. Noble Energy does not hold an interest in the LNG plant. The Company has recorded reserves based on minimum contractual volumes required to be taken under the LNG agreement.

 

At December 31, 2004, the Company held 45,203 gross developed acres and 1,112,841 gross undeveloped acres offshore Equatorial Guinea on which the Company may conduct future exploration activities. For more information, see “Item 2.  Properties—Crude Oil and Natural Gas” of this Form 10-K.

 

Israel. Noble Energy has been actively engaged in exploration, exploitation and development of crude oil and natural gas properties in the Mediterranean Sea, offshore Israel, since 1998. The Company owns a 47 percent interest in three licenses and two leases. At December 31, 2004, the Company held 123,552 gross developed acres and 292,572 gross undeveloped acres located about 20 miles offshore Israel in water depths ranging from 700 feet to 5,000 feet. On December 24, 2003, Noble Energy and its partners announced the commencement of production of natural gas from its Mari-B field. Sales of natural gas to The Israel Electric Corporation Limited (“IEC”) began in February 2004 under a definitive agreement executed in June 2002. In September 2004, the Company entered into a separate agreement to provide natural gas for use in the Bazan Refinery located in Ashdod, Israel. Sales to Bazan are expected to commence during the third quarter of 2005. 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 (the Netherlands and the United Kingdom) since 1996. At December 31, 2004, the Company held 42,723 gross developed acres and 540,310 gross undeveloped acres on which the Company may conduct future exploration activities. For more information, see “Item 2.  Properties—Crude Oil and Natural Gas” of this Form 10-K.

 

Vietnam. In December 2003, Noble Energy elected not to pursue any additional exploration efforts in the Nam Con Son Basin of Vietnam. As a result, the Company wrote off its investment in Vietnam and its ownership in two blocks.

 

4



 

Production Activities

 

Revenues from sales of crude oil, natural gas and gathering, marketing and processing (“GMP”) have accounted for approximately 90 percent or more of consolidated revenues for each of the last three fiscal years.

 

Operated Property Statistics. The percentage of properties operated by the Company indicates the amount of control over timing of operations. The percentage of operated crude oil and natural gas wells on both the well count and percentage of sales volume basis are shown in the following table as of December 31:

 

 

 

2004

 

2003

 

2002

 

(in percentages)

 

Oil

 

Gas

 

Oil

 

Gas

 

Oil

 

Gas

 

Operated well count basis

 

18.2

 

59.2

 

19.6

 

60.1

 

23.3

 

62.8

 

Operated sales volume basis

 

29.1

 

57.9

 

33.3

 

48.8

 

29.3

 

45.1

 

 

Non-operated Property Statistics. The percentage of non-operated crude oil and natural gas wells on both the well count and the percentage of sales volume basis are shown in the following table as of December 31:

 

 

 

2004

 

2003

 

2002

 

(in percentages)

 

Oil

 

Gas

 

Oil

 

Gas

 

Oil

 

Gas

 

Non-operated well count basis

 

81.8

 

40.8

 

80.4

 

39.9

 

76.7

 

37.2

 

Non-operated sales volume basis

 

70.9

 

42.1

 

66.7

 

51.2

 

70.7

 

54.9

 

 

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

 

 

 

2004

 

2003

 

2002

 

Crude oil production (MMBbls)

 

16.6

 

13.1

 

10.6

 

Natural gas production (Bcf)

 

134.3

 

122.9

 

124.5

 

 

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

 

 

 

2004

 

2003

 

2002

 

Total crude oil equivalents (MMBoe)

 

39.0

 

33.6

 

31.4

 

Total natural gas equivalents (Bcfe)

 

234.0

 

201.7

 

188.2

 

 

Acquisitions of Oil and Gas Properties, Leases and Concessions

 

During 2004, Noble Energy spent approximately $85.8 million on the purchase of proved crude oil and natural gas properties. The Company spent approximately $1.3 million in 2003 and $8.0 million in 2002 on the acquisition of proved crude oil and natural gas properties. For more information, see “Item 2.  Properties—Crude Oil and Natural Gas” of this Form 10-K.

 

During 2004, Noble Energy spent approximately $44.7 million on acquisitions of unproved properties. The Company spent approximately $10.2 million in 2003 and $30.5 million in 2002 on acquisitions of unproved properties. These properties were acquired 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.

 

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Dispositions of Oil and Gas Properties

 

During 2004, the Company completed its asset disposition program announced in July 2003. The sales price for the five packages of properties, before closing adjustments, totaled approximately $130 million. The properties held for disposition were reported as discontinued operations. The estimated reserves associated with these five packages were 24.2 MMBoe.

 

Marketing

 

NEMI seeks opportunities to enhance the value of the Company’s domestic natural gas production by marketing directly to end-users and aggregating natural gas to be sold to natural gas marketers and pipelines. During 2004, approximately 79 percent of NEMI’s total sales were to end-users. NEMI is also actively involved in the purchase and sale of natural gas from other producers. Such third-party natural gas production may be purchased from non-operators who own working interests in the Company’s wells or from other producers’ properties in which the Company may not own an interest. NEMI, through its wholly-owned subsidiary, Noble Gas Pipeline, Inc., engages in the installation, purchase and operation of natural gas gathering systems.

 

Noble Energy has a long-term natural gas sales contract with NEMI, whereby the Company is paid an index price for all natural gas sold to NEMI. The contract does not specify scheduled quantities or delivery points and expires on May 31, 2009. The Company sold approximately 56 percent of its natural gas production to NEMI in 2004. NEMI’s revenues from sales of natural gas, including related derivative transactions, less cost of goods sold, are reported in GMP. All intercompany sales and expenses are eliminated in the Company’s consolidated financial statements. The Company has a small number of long-term natural gas contracts with third parties representing approximately 12 percent of its 2004 natural gas sales.

 

Substantial competition in the natural gas marketplace continued in 2004. The Company’s average natural gas price from continuing operations, inclusive of the impact of commodity derivatives, increased $.61 from $4.13 per Mcf in 2003 to $4.74 per Mcf in 2004. Due to the volatility of natural gas prices, the Company has used derivative instruments and may do so in the future as a means of controlling its exposure to commodity price changes. For additional information, see “Item 7a. Quantitative and Qualitative Disclosures About Market Risk” and “Item 8. Financial Statements and Supplementary Data” of this Form 10-K.

 

Crude oil produced by the Company is sold to purchasers in the United States and foreign locations at various prices depending on the location and quality of the crude oil.  The Company has no long-term contracts with purchasers of its crude oil production. Crude oil and condensate are distributed through pipelines and by trucks to gatherers, transportation companies and end-users. NEMI markets approximately 42 percent of the Company’s crude oil production as well as certain third-party crude oil. The Company records all of NEMI’s revenues from sales of crude oil, less cost of goods sold, as GMP. All intercompany sales and expenses are eliminated in the Company’s consolidated financial statements.

 

Crude oil prices are affected by a variety of factors that are beyond the control of the Company. The Company’s average crude oil price from continuing operations, inclusive of the impact of commodity derivatives, increased $6.81 from $27.72 per Bbl in 2003 to $34.53 per Bbl in 2004. Due to the volatility of crude oil prices, the Company has used derivative instruments and may do so in the future as a means of controlling its exposure to commodity price changes. For additional information, see “Item 7a. Quantitative and Qualitative Disclosures About Market Risk” and “Item 8. Financial Statements and Supplementary Data” of this Form 10-K.

 

The largest single non-affiliated purchaser of the Company’s crude oil production in 2004 accounted for approximately 24 percent of the Company’s crude oil sales, representing approximately 10 percent of total revenues. The five largest purchasers accounted for approximately 68 percent of total crude oil sales. The largest single non-affiliated purchaser of the Company’s natural gas production in 2004 accounted for approximately eight percent of its natural gas sales, representing approximately four percent of total revenues. The five largest purchasers accounted

 

6



 

for approximately 24 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, among others, allowable rates of production, prevention of waste and pollution and protection of the environment. Laws affecting the crude oil and natural gas industry are under constant review for amendment or expansion and frequently increase the regulatory burden on companies. Noble Energy’s ability to economically produce and sell crude oil and natural gas is affected by a number of legal and regulatory factors, including federal, state and local laws and regulations in the United States and laws and regulations of foreign nations. Many of these governmental bodies have issued rules and regulations that are often difficult and costly to comply with, and that carry substantial penalties for failure to comply. These laws, regulations and orders may restrict the rate of crude oil and natural gas production below the rate that would otherwise exist in the absence of such laws, regulations and orders. The regulatory burden on the crude oil and natural gas industry increases its costs of doing business and consequently affects the Company’s profitability.

 

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

 

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

 

The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as “Superfund,” imposes liability on certain classes of persons that generated hazardous substances that have been released into the environment or that own or operate facilities or vessels onto or into which hazardous substances are disposed. The Resource Conservation and Recovery Act, as amended, (“RCRA”) and regulations promulgated thereunder, regulate hazardous waste, including its generation, treatment, storage and disposal. CERCLA currently exempts crude oil, and RCRA currently exempts certain crude oil and natural gas exploration and 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

 

7



 

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 do not generally impose an additional compliance burden on the Company or on its subsidiaries.

 

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

 

Insurance. The Company has various types of insurance coverages as are customary in the industry that include directors and officers liability, general liability, well control, pollution, terrorism acts, physical damage insurance and business interruption insurance for certain international locations. The Company self-insures, is a shareholder in an industry mutual insurance company and purchases policies from third party insurance providers to cover various risks. The Company believes the coverages and types of insurance are adequate.

 

Competition

 

The oil and gas industry is highly competitive. Many companies and individuals are engaged in exploring for crude oil and natural gas and acquiring crude oil and natural gas properties, resulting in a high degree of competition for desirable exploratory and producing properties. A number of the companies with which the Company competes are larger and have greater financial resources than the Company.

 

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

 

Unconsolidated Subsidiaries

 

AMCCO, AMPCO, AMPCO Marketing LLC, AMPCO Services LLC and Samedan Methanol are accounted for using the equity method. The Company owns a 45 percent interest in AMPCO through its 50 percent ownership in AMCCO. AMPCO completed construction of a methanol plant in Equatorial Guinea in the second quarter of 2001.

 

The plant construction started during 1998, and initial production of commercial grade methanol commenced May 2, 2001. The plant is designed to produce 2,500 MTpd of methanol, which equates to approximately 20,000 Bpd. At this level of production, the plant would purchase approximately 125 MMcfpd of natural gas from the Alba field in which Noble Energy owns a 34 percent interest. The methanol plant has a contract, which runs through 2026, to purchase natural gas from the Alba field. The Company’s investment in the methanol plant is included in investment in unconsolidated subsidiaries on the Company’s balance sheets, and the Company’s share of earnings from its unconsolidated subsidiaries is reported in the revenue section of the Company’s statements of operations as

 

8



 

income from unconsolidated subsidiaries. For more information, see “Item 8. Financial Statements and Supplementary Data—Note 13 - Unconsolidated Subsidiaries” of this Form 10-K.

 

Geographical Data

 

The Company has operations throughout the world and manages its operations by country. Information is grouped into five components that are all primarily in the business of crude oil and natural gas exploration, exploitation and production: United States, Equatorial Guinea, North Sea, Israel, and Other International, Corporate and Marketing. For more information, see “Item 8. Financial Statements and Supplementary Data—Note 15 - Geographical Data” of this Form 10-K.

 

Employees

 

The total number of employees of the Company decreased during the year from 583 at December 31, 2003 to 559 at December 31, 2004. In addition, 173 foreign nationals worked in Noble Energy offices in China, Ecuador, Equatorial Guinea, Israel and the United Kingdom as of December 31, 2004.

 

Available Information

 

The Company’s website address is www.nobleenergyinc.com. Available on this website under “Investor Relations -Investor Relations Menu - SEC Filings,” free of charge, are Noble Energy’s annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Forms 3, 4 and 5 filed on behalf of directors and officers and amendments to those reports as soon as reasonably practicable after such materials are electronically filed with or furnished to the SEC.

 

Also posted on the Company’s website, and available in print upon request of any stockholder to the Investor Relations Department, are charters for the Company’s Audit Committee; Compensation, Benefits and Stock Option Committee; Corporate Governance and Nominating Committee; and Environment, Health and Safety Committee. Copies of the Code of Business Conduct and Ethics, and the Code of Ethics for Chief Executive and Senior Financial Officers governing our directors, officers and employees (the “Codes”) are also posted on the Company’s website under the “Corporate Governance” section. Within the time period required by the SEC and the NYSE, as applicable, the Company will post on its website any modifications to the Codes and any waivers applicable to senior officers as defined in the applicable Code, as required by the Sarbanes-Oxley Act of 2002 (“Sarbanes-Oxley”).

 

In 2004, the Company submitted the annual certification of its Chief Executive Officer regarding the Company’s compliance with the NYSE’s corporate governance listing standards, pursuant to Section 303A.12(a) of the NYSE Listed Company Manual. A supplemental certification was delivered subsequently to the NYSE following the unexpected death of one of the Company’s independent directors.

 

Item 2.                                   Properties.

 

For crude oil and natural gas reserve information, see “Item 8. Financial Statements and Supplementary Data—Supplemental Oil and Gas Information” of this Form 10-K.

 

Offices

 

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

 

9



 

Crude Oil and Natural Gas

 

The Company searches for potential crude oil and natural gas properties, seeks to acquire exploration rights in areas of interest and conducts exploratory activities. These activities include geophysical and geological evaluation and exploratory drilling, where appropriate, on properties for which it acquired exploration rights. During 2004, Noble Energy drilled or participated in the drilling of 225 gross (108.8 net) wells, comprised of 95 gross (18.6 net) international wells and 130 gross (90.2 net) domestic wells. For more information regarding Noble Energy’s oil and gas properties, see “Item 1. Business—Crude Oil and Natural Gas” of this Form 10-K.

 

Domestic Offshore. During 2004, Noble Energy’s offshore drilling program included 19 gross (8.1 net) exploration and development wells. Of the wells drilled in 2004, 10 wells, or 53 percent, were commercial discoveries, seven wells were exploratory dry holes and two were development dry holes.

 

Viosca Knoll Block 917, 961 and 962 (“Swordfish”), a 2001 deepwater discovery, is located in approximately 4,500 feet of water. During 2004, Noble Energy acquired all of BP Exploration & Production, Inc.’s 50 percent working interest, increasing the Company’s working interest from 10 percent to 60 percent. Two well penetrations found crude oil and natural gas pay in multiple, high-quality reservoirs. During 2005, the three wells will be connected to existing infrastructure through subsea tiebacks. Production is expected to commence in the second quarter of 2005 at an initial rate of approximately 10,000 Boepd, net to Noble Energy. The Company recorded net reserves of 9.6 MMBoe in 2004.

 

Green Canyon 199 (“Lorien”), a July 2003 deepwater crude oil discovery, is located in approximately 2,200 feet of water. During 2004, Noble Energy acquired an additional interest in Lorien from ConocoPhillips. The acquisition increased the Company’s working interest from 20 percent to 60 percent and Noble Energy now operates the block. The discovery well was drilled to a total measured depth of 18,703 feet (or a total vertical depth of 17,432 feet) and encountered more than 120 feet of net pay, primarily crude oil. A successful appraisal sidetrack well was drilled in 2004 and a second appraisal well will be drilled in the first quarter of 2005. Both wells will be completed and tied back to area infrastructure during late 2005 or early 2006. Production is expected to commence in the first half of 2006 at an initial rate of approximately 12,000 Boepd, net to Noble Energy. The Company did not record any reserves on this property in 2004.

 

Green Canyon 768 (“Ticonderoga”), a 2004 deepwater crude oil discovery, is located near Kerr-McGee’s Constitution development on Green Canyon Block 680 and will be a subsea tieback to the planned Constitution spar. The Ticonderoga well spud on March 21, 2004 and is located in approximately 5,300 feet of water. The well drilled to a total measured depth of 13,556 feet (or a total vertical depth of 13,370 feet). The well encountered over 250 feet of net high-quality pay, primarily crude oil. The Company recorded net reserves of 15.9 MMBoe in 2004 from this discovery. Production is expected to commence by mid-2006 at an initial rate of approximately 10,000 to 12,000 Boepd, net to Noble Energy. The Company has a 50 percent working interest.

 

Noble Energy increased its working interest in the Eugene Island 254 field from 30 percent to 100 percent. After completing a successful two-well program, consisting of sidetracking and completing one well and recompleting another well, production was re-established in the field in November 2004 at a producing net rate of 1,300 Boepd.

 

Noble Energy was the successful bidder, alone or with partners, on 24 of 26 lease blocks at the Central Gulf of Mexico Outer Continental Shelf (the “Shelf”) Sale 190. On the Shelf, the Company bid on 24 lease blocks and was the high bidder on 22 lease blocks. All of the 22 blocks on which Noble Energy was the high bidder contain deep objectives below 15,000 feet. In the deepwater, the Company was the high bidder on two blocks. Net to the Company’s interest, the high bids totaled approximately $6.1 million. Noble Energy concentrated its bids on opportunities in the West Cameron, Chandeleur Sound and Mobile areas.

 

10



 

Domestic Onshore. During 2004, Noble Energy’s onshore drilling program included 111 gross (82.1 net) exploration and development wells. Of the wells drilled in 2004, 94 wells, or 85 percent, were commercial discoveries and 17 wells were dry holes. Of the 17 dry holes, nine were exploratory and expensed.

 

Activity in the onshore Gulf Coast region in 2004 remained high with 31 wells drilled, of which 24, or 77 percent, were successful. The majority of Noble Energy’s onshore exploration focus in 2004 was in the Gulf Coast region, where 15 out of 22 exploration wells were successfully completed.

 

In Duval County, Texas, Noble Energy drilled 10 wells, of which eight were successful. The prospects were identified with proprietary 3-D seismic acquired in late 2002. The eight successful wells were producing 2,930 Boepd, gross, at year-end 2004. Noble Energy’s working interests in the wells drilled in 2004 range from 85 percent to 100 percent.

 

During the year, the Company’s onshore development activity was focused in the Mid-continent and Rockies regions where 69 out of 77 development wells were successfully completed.

 

In the Niobrara Trend of northeast Colorado, results of infill drilling pilot programs were used to obtain area-wide regulatory approval for 40-acre development of the Niobrara formation. As a result of the regulatory approval that was granted late in the year, Noble Energy initiated an aggressive development drilling program. The Company plans to drill up to 235 Niobrara development wells in 2005.

 

Another rapidly growing area is the Piceance Basin in western Colorado. Noble Energy was successful in acquiring approximately 7,000 acres in the Piceance Basin in 2004 and began drilling several wells late in the year. The program is expected to continue in 2005.

 

Argentina. Noble Energy participated with a 13 percent working interest in 77 development wells in the El Tordillo field during 2004. The Company has been awarded, and is awaiting final government approval on, an operated crude oil and natural gas exploration permit of approximately 1.2 million acres. The permit is located adjacent to an existing permit of approximately 1.2 million acres in the Cuyo Basin of Mendoza Province in western Argentina.

 

China. Noble Energy, as operator, has a 57 percent working interest in the Cheng Dao Xi (“CDX”) field, which is located on the south side of Bohai Bay off the coast of China. Initial production from CDX commenced on January 13, 2003. During 2004, CDX averaged 3,883 Bopd net to Noble Energy.

 

Noble Energy continued its development of the CDX field with a successful drilling program in 2004. The results increased production above 5,000 Bopd net to Noble Energy at the end of 2004. The Company plans to drill two additional development wells in 2005.

 

Ecuador. In September 2002, Noble Energy commenced operations of its 100 percent-owned integrated natural gas-to-power project. The project includes the Amistad field, which is located in the shallow waters of the Gulf of Guayaquil near the coast of Ecuador. The power plant is located on the coast near Machala, Ecuador and connects to the Amistad field via a 40-mile pipeline. The Machala Power Plant is the only natural gas-fired commercial power generator in Ecuador and currently has a generating capacity of 130 MW of electricity from twin General Electric Frame 6Fa turbines. In 2004, the Company implemented a successful drilling program in the Amistad field that is projected to provide plant feedstock into the next decade.

 

Equatorial Guinea. During 2002, Noble Energy and its partners obtained approval from the government of Equatorial Guinea for Phases 2A and 2B Alba field expansion projects. The Phase 2A project included adding two platforms, 12 wells, three pipelines and two compressors. Initial startup of Phase 2A began in November 2003. The Phase 2A expansion is expected to increase condensate production by approximately 8,400 Bpd net to Noble Energy.

 

Phase 2B, which is scheduled to be completed during 2005, is expected to increase production of LPG by approximately 3,900 Bpd net to Noble Energy and condensate production by approximately 1,800 Bpd net to Noble

 

11



 

Energy. This project includes increasing processing capacity, storage and offloading facilities at the existing LPG plant.

 

Following the ramp-up of Phase 2A in 2005 and the completion of Phase 2B, condensate and LPG capacity will be approximately 15,800 Bpd net to Noble Energy and 4,700 Bpd net to Noble Energy, respectively.

 

Noble Energy, through its subsidiaries, holds a 34 percent working interest in the offshore Alba field and related condensate production facilities, a 28 percent interest in the Alba LPG plant and a 45 percent interest in the AMPCO plant. The AMPCO plant purchases and processes approximately 125 MMcfpd of natural gas into 2,500 MTpd of methanol.

 

In 2004, Noble Energy signed a Production Sharing Contract (“PSC”) with the Republic of Equatorial Guinea covering Block “O” offshore Bioko Island and acquired an interest in a PSC for Block “I”, also located offshore Bioko Island. Under the terms of these agreements, Noble Energy will be Technical Operator with a 45 percent working interest in Block “O” and a 40 percent working interest in Block “I”. Exploration drilling is expected to begin in 2005 on Block “O”.

 

Israel. The Company and its partners have an agreement to provide approximately 170 MMcfpd of natural gas for use in IEC’s power plants. In September 2004, the Company entered into a separate agreement to provide approximately 11 MMcfpd of natural gas for use in the Bazan Refinery located in Ashdod, Israel. Natural gas is produced from the Mari-B field, which was discovered in 2000, offshore Israel. Sales to IEC commenced February 18, 2004 and sales to Bazan are expected to commence during the third quarter of 2005. Noble Energy has a 47 percent working interest in the Mari-B field. During 2004, the Mari-B field averaged 48 MMcfpd net to Noble Energy. The Company has two additional discoveries offshore Israel, which are planned to be subsea tied into the Mari-B platform.

 

North Sea. The Company continued to focus on production and exploration growth in 2004 and added reserves in producing fields. The Company participated in two successful non-operated appraisal wells in the U.K. sector of the North Sea, one of which is expected to lead to the development of the Dumbarton field during 2005 and 2006. The Company also participated in drilling an exploratory dry hole in the Danish sector, the license for which has been subsequently relinquished.

 

During the year, the Company entered into an exchange agreement with Talisman Energy (UK) Limited whereby the Company disposed of its interests in the producing Buchan and Hannay fields and the Tweedsmuir development project in exchange for a producing interest in the MacCulloch field and cash.

 

12



 

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

 

 

 

Net Exploratory Wells

 

Net Development Wells

 

Year Ended

 

Productive(1)

 

Dry(2)

 

Productive(1)

 

Dry(2)

 

December 31,

 

U.S.

 

Int’l

 

U.S.

 

Int’l

 

U.S.

 

Int’l

 

U.S.

 

Int’l

 

2004

 

10.70

 

.30

 

8.45

 

1.05

 

62.37

 

17.25

 

8.73

 

 

 

2003

 

10.84

 

.07

 

12.40

 

2.67

 

25.10

 

7.32

 

8.16

 

 

 

2002

 

9.78

 

 

 

11.45

 

3.27

 

41.53

 

12.84

 

11.17

 

 

 

 


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

 

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

 

At January 31, 2005, Noble Energy was drilling 3 gross (1.1 net) exploratory wells and 13 gross (5.7 net) development wells. These wells are located onshore in Colorado, Louisiana, Montana, Oklahoma, Texas, Argentina and offshore Equatorial Guinea and the Gulf of Mexico. These wells have objectives ranging from approximately 1,700 feet to 25,000 feet. The drilling cost to Noble Energy of these wells will be approximately $13.9 million if all are dry and approximately $18.2 million if all are completed as producing wells.

 

13



 

Crude Oil and Natural Gas Wells. Due to the various asset dispositions in 2003 and 2004, there was a significant decrease from 2002 in the number of wells in which Noble Energy held an interest. The number of productive crude oil and natural gas wells in which Noble Energy held an interest as of December 31 follows:

 

 

 

2004(1)(2)

 

2003(1)(2)

 

2002(1)(2)

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Crude Oil Wells

 

 

 

 

 

 

 

 

 

 

 

 

 

United States – Onshore

 

179.0

 

105.9

 

196.0

 

118.2

 

1,131.0

 

458.7

 

United States – Offshore

 

165.0

 

109.2

 

186.0

 

114.2

 

232.0

 

95.7

 

International

 

713.0

 

98.6

 

716.0

 

88.8

 

687.0

 

81.3

 

Total

 

1,057.0

 

313.7

 

1,098.0

 

321.2

 

2,050.0

 

635.7

 

Natural Gas Wells

 

 

 

 

 

 

 

 

 

 

 

 

 

United States – Onshore

 

1,728.0

 

1,121.5

 

1,645.0

 

1,042.1

 

1,603.0

 

1,006.6

 

United States – Offshore

 

167.0

 

73.5

 

299.0

 

116.5

 

265.0

 

184.9

 

International

 

28.0

 

10.3

 

34.0

 

8.4

 

42.0

 

13.1

 

Total

 

1,923.0

 

1,205.3

 

1,978.0

 

1,167.0

 

1,910.0

 

1,204.6

 

 


(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.

 

 

 

2004

 

2003

 

2002

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Multiple Completions

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil

 

7.0

 

4.6

 

9.0

 

5.8

 

12.0

 

6.0

 

Natural Gas

 

20.0

 

8.1

 

29.0

 

11.3

 

28.0

 

8.9

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Not Producing (Shut-in)

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil

 

516.0

 

102.5

 

573.0

 

109.2

 

565.0

 

212.3

 

Natural Gas

 

297.0

 

127.2

 

337.0

 

142.5

 

121.0

 

73.0

 

 

At year-end 2004, Noble Energy had less than 16 percent of its crude oil and natural gas sales volumes, on an Mcfe basis, committed to long-term supply contracts and had no similar agreements with foreign governments or authorities.

 

Since January 1, 2004, 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.

 

SEC guidelines do not limit reserve bookings to only contracted volumes if it can be demonstrated that there is reasonable certainty that a market exists. The Company has booked reserves in excess of contracted volumes for Israel due to the reasonable certainty of the existence of markets in future periods. In Israel, the Company has a natural gas contract with IEC, which is expected to run through 2014, and a contract with the Israel Bazan Refinery

 

14



 

through the year 2015. The Israeli natural gas market, as estimated by the Israeli Ministry of National Infrastructure, from 2005 to 2020, is significantly greater than Noble Energy’s uncontracted net estimated proved reserves.

 

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

 

 

 

Year Ended December 31,

 

 

 

2004

 

2003

 

2002

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

$

31.90

 

$

26.21

 

$

23.29

 

International

 

$

36.94

 

$

28.94

 

$

24.98

 

 

 

 

 

 

 

 

 

Combined (2)

 

$

34.53

 

$

27.72

 

$

24.22

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

$

6.00

 

$

4.75

 

$

3.24

 

International (3)

 

$

1.88

 

$

1.17

 

$

1.18

 

 

 

 

 

 

 

 

 

Combined (4)

 

$

4.74

 

$

4.13

 

$

2.89

 

 

 

 

 

 

 

 

 

Average production cost per BOE (5):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

$

5.46

 

$

4.43

 

$

3.76

 

International

 

$

4.99

 

$

5.40

 

$

4.16

 

 

 

 

 

 

 

 

 

Combined

 

$

5.27

 

$

4.78

 

$

3.88

 

 


(1)          Includes royalties.

 

(2)          Reflects a reduction of $3.05 per Bbl in 2004, $1.01 per Bbl in 2003 and $.02 per Bbl in 2002 from hedging in the United States.

 

(3)          Ecuador natural gas revenues and natural gas production volumes are excluded in the calculation of the International average sales price per Mcf of natural gas. The natural gas-to-power project in Ecuador is 100 percent owned by Noble Energy. Intercompany natural gas sales are eliminated for accounting purposes.

 

(4)          Reflects a reduction of $.08 per Mcf in 2004 and $.44 per Mcf in 2003 and an increase of $.05 per Mcf in 2002 from hedging in the United States.

 

(5)          Oil and gas production costs include lease operating expense, production taxes, ad valorem taxes, workover expense and transportation costs.

 

15



 

 

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

 

 

Block

 

Working
Interest (%)

 

 

 

 

 

East Breaks

 

 

 

464

 *

 

48

 

465

 *

 

48

 

475

 *

 

100

 

510

 *

 

33

 

519

 *

 

100

 

563

 *

 

100

 

 

 

 

 

 

Green Canyon

 

 

 

85

 *

 

50

 

142

 

 

100

 

185

 *

 

100

 

186

 *

 

100

 

187

 *

 

100

 

199

 *

 

60

 

228

 *

 

100

 

238

 *

 

40

 

303

 *

 

40

 

507

 *

 

50

 

723

 *

 

100

 

724

 *

 

100

 

767

 *

 

50

 

955

 *

 

7

 

958

 *

 

25

 

 

 

 

 

 

East Cameron

 

 

 

342

 

 

50

 

348

 

 

30

 

355

 

 

100

 

 

 

 

 

 

South Timbalier

 

 

 

62

 

 

100

 

278

 

 

50

 

 

 

 

 

 

Ship Shoal

 

 

 

73

 

 

50

 

 

 

 

 

 

Mustang Island

 

 

 

829

 

 

50

 

830

 

 

50

 

831

 

 

60

 

 

 

 

 

 

Vermilion

 

 

 

208

 

 

25

 

227

 

 

50

 

228

 

 

50

 

230

 

 

100

 

235

 

 

100

 

352

 

 

100

 

353

 

 

100

 

391

 

 

100

 

 

 

 

 

 

Garden Banks

 

 

 

25

 

 

50

 

416

 *

 

100

 

460

 *

 

100

 

461

 *

 

100

 

751

 *

 

100

 

795

 *

 

100

 

841

 *

 

39

 

 

 

 

 

 

Main Pass

 

 

 

107

 

 

25

 

110

 

 

25

 

 

 

 

 

 

South Marsh Island

 

 

 

4

 

 

100

 

38

 

 

100

 

145

 

 

100

 

195

 

 

50

 

 

 

 

 

 

Viosca Knoll

 

 

 

23

 

 

100

 

65

 

 

100

 

157

 

 

100

 

383

 

 

24

 

908

 *

 

100

 

 

 

 

 

 

Mississippi Canyon

 

 

 

26

 *

 

75

 

70

 *

 

75

 

71

 *

 

75

 

115

 *

 

75

 

116

 *

 

100

 

122

 *

 

75

 

123

 *

 

75

 

159

 *

 

75

 

204

 *

 

100

 

524

 *

 

50

 

595

 *

 

24

 

602

 *

 

75

 

639

 *

 

24

 

665

 *

 

50

 

769

 *

 

100

 

811

 *

 

30

 

849

 *

 

34

 

855

 *

 

30

 

856

 *

 

30

 

857

 *

 

30

 

892

 *

 

35

 

896

 *

 

67

 

900

 *

 

30

 

901

 *

 

30

 

911

 *

 

40

 

999

 *

 

30

 

1000

 *

 

30

 

 

 

 

 

 

Chandeleur Sound

 

 

 

1

 

 

100

 

4

 

 

100

 

18

 

 

100

 

39

 

 

100

 

 

 

 

 

 

Mobile

 

 

 

 

942

 

 

100

 

943

 

 

100

 

987

 

 

100

 

 

 

 

 

 

Ewing Bank

 

 

 

834

 *

 

14

 

949

 

 

52

 

993

 

 

53

 

 

 

 

 

 

High Island

 

 

 

A-218

 

 

100

 

A-230

 

 

100

 

A-422

 

 

100

 

A-587

 

 

3

 

 

 

 

 

 

Atwater Valley

 

 

 

10

 *

 

100

 

11

 *

 

100

 

23

 *

 

100

 

66

 *

 

100

 

67

 *

 

100

 

327

 *

 

79

 

533

 *

 

40

 

 

 

 

 

 

West Cameron

 

 

 

359

 

 

100

 

360

 

 

100

 

372

 

 

100

 

373

 

 

100

 

389

 

 

100

 

392

 

 

100

 

393

 

 

100

 

400

 

 

100

 

404

 

 

100

 

405

 

 

100

 

406

 

 

100

 

411

 

 

100

 

412

 

 

100

 

418

 

 

100

 

419

 

 

100

 

420

 

 

100

 

421

 

 

100

 

422

 

 

50

 

423

 

 

100

 

438

 

 

100

 

443

 

 

100

 

446

 

 

100

 

 


*Located in water deeper than 1,000 feet.

 

16



 

The developed and undeveloped acreage (including both leases and concessions) that Noble Energy held as of December 31, 2004, is as follows:

 

 

 

Developed Acreage (1)(2)

 

Undeveloped Acreage (2)(3)(4)

 

Location

 

Gross Acres

 

Net Acres

 

Gross Acres

 

Net Acres

 

United States Onshore

 

 

 

 

 

 

 

 

 

Alabama

 

 

 

 

 

2,926

 

505

 

California

 

812

 

333

 

25,459

 

8,181

 

Colorado

 

79,252

 

60,372

 

37,578

 

31,046

 

Kansas

 

92,956

 

52,627

 

21,604

 

14,222

 

Louisiana

 

31,030

 

10,709

 

29,613

 

11,498

 

Michigan

 

 

 

 

 

1,876

 

427

 

Mississippi

 

878

 

34

 

1,884

 

51

 

Montana

 

201,783

 

123,603

 

3,798

 

1,452

 

Nevada

 

 

 

 

 

61,076

 

60,031

 

New Mexico

 

1,797

 

897

 

2,200

 

1,613

 

North Dakota

 

 

 

 

 

685

 

314

 

Oklahoma

 

136,057

 

47,385

 

11,353

 

5,521

 

Texas

 

74,421

 

30,818

 

82,115

 

30,257

 

Utah

 

1,280

 

260

 

8,514

 

5,446

 

Wyoming

 

25,009

 

10,928

 

61,983

 

32,970

 

Total United States Onshore

 

645,275

 

337,966

 

352,664

 

203,534

 

United States Offshore (Federal Waters)

 

 

 

 

 

 

 

 

 

Alabama

 

92,160

 

45,158

 

37,834

 

32,081

 

California

 

38,833

 

12,039

 

52,364

 

9,422

 

Louisiana

 

376,634

 

164,810

 

402,938

 

320,704

 

Mississippi

 

37,756

 

19,260

 

138,240

 

74,870

 

Texas

 

158,946

 

73,560

 

117,791

 

85,145

 

Total United States Offshore (Federal Waters)

 

704,329

 

314,827

 

749,167

 

522,222

 

International

 

 

 

 

 

 

 

 

 

Argentina

 

113,325

 

15,548

 

2,341,884

 

2,341,884

 

China

 

7,413

 

4,225

 

 

 

 

 

Ecuador

 

12,355

 

12,355

 

851,771

 

851,771

 

Equatorial Guinea

 

45,203

 

15,727

 

1,112,841

 

481,291

 

Israel

 

123,552

 

58,142

 

292,572

 

137,681

 

Netherlands

 

865

 

130

 

74,749

 

11,212

 

United Kingdom

 

41,858

 

3,536

 

465,561

 

131,263

 

Total International

 

344,571

 

109,663

 

5,139,378

 

3,955,102

 

 

 

 

 

 

 

 

 

 

 

Total (5)

 

1,694,175

 

762,456

 

6,241,209

 

4,680,858

 

 


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

 

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

 

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

 

(4)          The Argentina acreage includes one concession totaling 1,163,865 acres subject to final governmental approval.

 

(5)          If production is not established, approximately 143,507 gross acres (88,350 net acres), 248,777 gross acres (127,235 net acres) and 91,175 gross acres (71,700 net acres) will expire during 2005, 2006 and 2007, respectively.

 

17



 

Item 3.                                   Legal Proceedings.

 

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

 

On October 15, 2002, Noble Gas Marketing, Inc. and Samedan Oil Corporation, collectively referred to as the “Noble Defendants,” filed proofs of claim in the United States Bankruptcy Court for the Southern District of New York in response to bankruptcy filings by Enron Corporation and certain of its subsidiaries and affiliates, including Enron North America Corporation (“ENA”), under Chapter 11 of the U.S. Bankruptcy Code. The proofs of claim relate to certain natural gas sales agreements and aggregate approximately $12 million.

 

On December 13, 2002, ENA filed a complaint in which it objected to the Noble Defendants’ proofs of claim, sought recovery of approximately $60 million from the Noble Defendants under the natural gas sales agreements, sought declaratory relief in respect of the offset rights of the Noble Defendants and sought to invalidate the arbitration provisions contained in certain of the agreements at issue.

 

On January 13, 2003, the Noble Defendants filed an answer to ENA’s complaint. On January 29, 2003, the Noble Defendants filed the Motion of Noble Energy Marketing, Inc., as Successor to Noble Gas Marketing, Inc., and Noble Energy, Inc., as Successor to Samedan Oil Corporation, to Compel Arbitration. On March 4, 2003, the Court issued its Order Governing Mediation of Trading Cases and Appointing the Honorable Allan L. Gropper as Mediator (the “Mediation Order”) which, among other things, abated this case and referred it to mediation along with other pending adversary proceedings in the Enron bankruptcy cases which involve disputes arising from or in connection with commodity trading contracts. Pursuant to the Mediation Order, the Honorable Allan L. Gropper (United States Bankruptcy Judge for the Southern District of New York) has acted as mediator for this case and the other trading cases which have been referred to him. Mediation sessions for this case were held on December 17, 2003 and May 21, 2004. In January 2005, the parties reached a preliminary settlement of matters in dispute subject to the approval of ENA’s internal committees, the board of directors of Enron Corp., and the United States Bankruptcy Court. The proposed settlement, if approved, will not have a material adverse effect on the Company’s consolidated financial position, results of operations or liquidity. The Company was adequately reserved for this settlement and there will be no resulting gain or loss.

 

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 2004.

 

18



 

Executive Officers of the Registrant

 

The following table sets forth certain information, as of March 14, 2005, with respect to the executive officers of the Registrant.

 

Name

 

Age

 

Position

 

 

 

 

 

Charles D. Davidson (1)

 

55

 

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

 

 

 

 

 

Alan R. Bullington (2)

 

53

 

Senior Vice President, International

 

 

 

 

 

Robert K. Burleson (3)

 

47

 

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

 

 

 

 

 

Susan M. Cunningham (4)

 

49

 

Senior Vice President, Exploration

 

 

 

 

 

Arnold J. Johnson (5)

 

49

 

Vice President, General Counsel and Secretary

 

 

 

 

 

James L. McElvany (6)

 

51

 

Senior Vice President

 

 

 

 

 

William A. Poillion, Jr. (7)

 

55

 

Senior Vice President, Production and Drilling

 

 

 

 

 

Ted A. Price (8)

 

45

 

Vice President, Domestic Onshore

 

 

 

 

 

David L. Stover (9)

 

47

 

Senior Vice President, Domestic and Business Development

 

 

 

 

 

Chris Tong (10)

 

48

 

Senior Vice President, Chief Financial Officer and Treasurer

 

 

 

 

 

Kenneth P. Wiley (11)

 

52

 

Vice President, Information Technology

 


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

 

(2)          Alan R. Bullington was elected a Senior Vice President of the Company on July 27, 2004. Prior thereto, he served as Vice President and General Manager, International Division of Samedan Oil Corporation beginning 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 Senior Vice President of the Company on July 27, 2004. Prior thereto, he served as Vice President of the Company since April 24, 2001 and has been in charge of the Company’s Business Administration Department since April 2002. He has also served as President of Noble Gas Marketing, Inc. (now Noble Energy Marketing, Inc.) since June 14, 1995. Prior thereto, he served as Vice President-Marketing for Noble Gas Marketing since its inception in 1994. Previous to his employment with the

 

19



 

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

 

(4)          Susan M. Cunningham was elected Senior Vice President of Exploration of the Company in April 2001. Prior to joining the Company, Ms. Cunningham was Texaco’s Vice President of worldwide exploration from April 2000 to March 2001. From 1997 through 1999, she was employed by Statoil, beginning in 1997 as Exploration Manager for deepwater Gulf of Mexico, appointed a Vice President in 1998 and responsible, in 1999, for Statoil’s West Africa exploration efforts. She joined Amoco in 1980 as a geologist and served in exploration and development positions of increasing responsibility until 1997.

 

(5)          Arnold J. Johnson was elected Vice President, General Counsel and Secretary of the Company on February 1, 2004. Prior thereto, he served as Associate General Counsel and Assistant Secretary of the Company from January 2001 through January 2004. Prior thereto, he served as Senior Counsel for BP America, Inc. from October 2000 to January 2001. Mr. Johnson held several positions as an attorney for Vastar and ARCO from March 1989 through September 2000, most recently as Assistant General Counsel and Assistant Secretary of Vastar from 1997 through 2000. He joined ARCO in 1980 as a landman and served in land management positions of increasing responsibility until 1989.

 

(6)          James L. McElvany was elected Senior Vice President, Chief Financial Officer and Treasurer of the Company in July 2002 and served as such through December 31, 2004. He remains with the Company as Senior Vice President and will aid in the transition process until his retirement, which will occur in the second quarter of 2005. Prior to July 2002, 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)          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.

 

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

 

(9)          David L. Stover was elected Senior Vice President of Domestic and Business Development of the Company on July 27, 2004. Prior thereto, he served as the Company’s Vice President of Business Development since 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, 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.

 

(10)    Chris Tong succeeded Mr. McElvany as Senior Vice President, Chief Financial Officer and Treasurer of the Company effective January 1, 2005. Prior to January 1, 2005, he had served as Senior Vice President and Chief Financial Officer for Magnum Hunter Resources, Inc. since August 1997. Prior thereto, he was Senior Vice President of Finance of Tejas Acadian Holding Company and its subsidiaries including Tejas Gas Corp., Acadian Gas Corporation and Transok, Inc., all of which were wholly-owned subsidiaries of Tejas Gas Corporation. Mr. Tong held these positions since August 1996, and served in other treasury positions with Tejas beginning August 1989. From 1980 to 1989, Mr. Tong served in various energy lending capacities with several commercial banking institutions. Prior to his banking career, Mr. Tong also served over a year with Superior Oil Company as a Reservoir Engineering Assistant.

 

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

 

20



 

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

 

21



PART II

 

Item 5.                                   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

 

Common Stock. The Registrant’s Common Stock, $3.33 1/3 par value (“Common Stock”), is listed and traded on the NYSE 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 NYSE and quarterly dividends paid per share.

 

 

 

High

 

Low

 

Dividends
Per Share

 

2004

 

 

 

 

 

 

 

First quarter

 

$

48.47

 

$

42.65

 

$

.05

 

Second quarter

 

$

52.06

 

$

43.61

 

$

.05

 

Third quarter

 

$

58.82

 

$

48.97

 

$

.05

 

Fourth quarter

 

$

64.60

 

$

56.62

 

$

.05

 

2003

 

 

 

 

 

 

 

First quarter

 

$

38.62

 

$

33.07

 

$

.04

 

Second quarter

 

$

40.02

 

$

32.37

 

$

.04

 

Third quarter

 

$

40.00

 

$

35.37

 

$

.04

 

Fourth quarter

 

$

45.99

 

$

37.48

 

$

.05

 

 

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

 

Stockholders’ Profile. Pursuant to the records of the transfer agent, as of February 25, 2005, the number of holders of record of Common Stock was 901. The following chart indicates the common stockholders by category.

 

February 25, 2005

 

Shares
Outstanding

 

Individuals

 

254,546

 

Joint accounts

 

45,096

 

Fiduciaries

 

118,183

 

Institutions

 

64,948

 

Nominees

 

58,560,874

 

Foreign

 

305

 

Total-excluding treasury shares

 

59,043,952

 

 

Sales of Unregistered Securities. The Company owns a 45 percent interest in AMPCO through its 50 percent ownership in AMCCO. During 1999, AMCCO issued $125 million Series A-2 senior secured notes due December 15, 2004 to fund construction payments owed in connection with the construction of the methanol plant. These notes were included on the Company’s balance sheet at December 31, 2003 and were repaid by the Company during 2004. The Company’s investment in the methanol plant is included in investment in unconsolidated subsidiaries.

 

Item 5c.                             Stock Repurchases.

 

The Company did not repurchase any of its outstanding Common Stock during 2004.

 

22



 

Item 6.                                   Selected Financial Data.

 

 

 

Year Ended December 31,

 

(in thousands, except per share amounts and ratios)

 

2004

 

2003

 

2002

 

2001

 

2000

 

Revenues and Income

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

1,351,176

 

$

1,005,950

 

$

701,332

 

$

794,588

 

$

729,168

 

Income from continuing operations

 

313,850

 

89,892

 

8,095

 

85,163

 

137,066

 

Net income

 

328,710

 

77,992

 

17,652

 

133,575

 

191,597

 

Per Share Data

 

 

 

 

 

 

 

 

 

 

 

Basic earnings per share:

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

$

5.39

 

$

1.58

 

$

0.14

 

$

1.51

 

$

2.45

 

Net income

 

$

5.64

 

$

1.37

 

$

0.31

 

$

2.36

 

$

3.42

 

Cash dividends

 

$

0.20

 

$

0.17

 

$

0.16

 

$

0.16

 

$

0.16

 

Year-end stock price

 

$

61.66

 

$

44.43

 

$

37.55

 

$

35.29

 

$

46.00

 

Basic weighted average shares outstanding

 

58,275

 

56,964

 

57,196

 

56,549

 

55,999

 

Financial Position (at year end)

 

 

 

 

 

 

 

 

 

 

 

Property, plant and equipment, net:

 

 

 

 

 

 

 

 

 

 

 

Oil and gas mineral interests, equipment and facilities

 

$

2,332,950

 

$

2,099,741

 

$

2,139,785

 

$

1,953,211

 

$

1,485,123

 

Total assets

 

3,443,171

 

2,842,649

 

2,730,015

 

2,604,255

 

2,002,819

 

Long-term obligations:

 

 

 

 

 

 

 

 

 

 

 

Long-term debt, net of current portion

 

880,256

 

776,021

 

977,116

 

961,118

 

648,567

 

Deferred income taxes

 

183,351

 

163,146

 

201,939

 

176,259

 

117,048

 

Asset retirement obligation

 

175,415

 

101,804

 

 

 

 

 

 

 

Other deferred credits and noncurrent liabilities

 

79,157

 

80,176

 

69,820

 

75,629

 

61,639

 

Shareholders’ equity

 

1,459,988

 

1,073,573

 

1,009,386

 

1,010,198

 

849,682

 

Ratio of debt-to-book capital (1)

 

.38

 

.46

 

.50

 

.50

 

.44

 

 


(1)          Defined as the Company’s total debt divided by the sum of total debt plus equity.

 

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

 

Operating Statistics – Continuing Operations

 

 

 

Year Ended December 31,

 

 

 

2004

 

2003

 

2002

 

2001

 

2000

 

Natural Gas

 

 

 

 

 

 

 

 

 

 

 

Sales (in millions)

 

$

582.2

 

$

457.6

 

$

341.1

 

$

487.4

 

$

492.0

 

Production (MMcfpd)

 

367.0

 

336.6

 

341.0

 

355.6

 

335.8

 

Average realized price (per Mcf)

 

$

4.74

 

$

4.13

 

$

2.89

 

$

3.86

 

$

4.09

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil

 

 

 

 

 

 

 

 

 

 

 

Sales (in millions)

 

$

565.3

 

$

358.0

 

$

252.3

 

$

208.6

 

$

124.9

 

Production (Bopd)

 

45,375

 

36,014

 

29,114

 

24,973

 

19,650

 

Average realized price (per Bbl)

 

$

34.53

 

$

27.72

 

$

24.22

 

$

23.49

 

$

18.21

 

 

 

 

 

 

 

 

 

 

 

 

 

Royalty sales (in millions)

 

$

26.7

 

$

23.5

 

$

15.6

 

$

20.9

 

$

17.3

 

 

23



 

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

 

Noble Energy is an independent energy company engaged, directly or through its subsidiaries or various arrangements with other companies, in the exploration, development, production and marketing of crude oil and natural gas. The Company has exploration, exploitation and production operations domestically and internationally. The domestic areas consist of: offshore in the Gulf of Mexico and California; the Gulf Coast Region (Louisiana and Texas); the Mid-continent Region (Oklahoma and Kansas); and the Rocky Mountain Region (Colorado, Montana, Nevada, Wyoming and California). The international areas of operations include Argentina, China, Ecuador, Equatorial Guinea, the Mediterranean Sea (Israel) and the North Sea (the Netherlands and the United Kingdom). The Company also markets domestic crude oil and natural gas production through a wholly-owned subsidiary, NEMI.

 

The Company’s accompanying consolidated financial statements, including the notes thereto, contain detailed information that should be referred to in conjunction with the following discussion.

 

EXECUTIVE OVERVIEW

 

Noble Energy’s principal business strategy has been to create shareholder value by generating stable cash flow and production from domestic operations, while generating growth from international projects. In the U.S., the Company has a substantial onshore and offshore asset base located in established, prolific basins where the Company is aggressively pursuing exploration and exploitation opportunities. Offshore, exploration focuses on the deepwater and deep shelf areas of the Gulf of Mexico. Internationally, the Company has built a strong project portfolio and has applied innovative approaches to developing markets for stranded natural gas, including construction of a natural gas-fired power plant near Machala, Ecuador, and liquefied petroleum gas and methanol plants in Equatorial Guinea.

 

The Company had a successful year, both financially and operationally, in 2004. Financial highlights included the following:

 

                  Record net income of $328.7 million, or $5.64 per share;

                  Cash flow from operating activities of $708.2 million;

                  A $48.7 million reduction in outstanding debt with a year-end debt-to-book capital ratio of 38 percent;

                  Issuance of $200 million senior notes;

                  Increased financial flexibility with an additional $400 million credit facility; and

                  Completion of asset disposition program first announced in July 2003.

 

Operational highlights included the following:

 

                  A 16 percent increase in daily equivalent production over 2003;

                  Ticonderoga deepwater discovery in the Gulf of Mexico;

                  New projects in the deepwater Gulf of Mexico;

                  Commencement of natural gas sales in Israel;

                  Phase 2A ramp-up in Equatorial Guinea; and

                  Acquisition of interests in two PSC’s with the Republic of Equatorial Guinea.

 

Domestic – Domestic operations benefited from higher realized prices for crude oil in 2004, and a four percent overall increase in production. During 2004, Noble Energy participated in 130 gross domestic exploration and development wells, of which 104 were successful.

 

Based on the results of successful infill pilot projects drilled during 2004, regulatory approval for 40-acre drilling density was granted for development of the Niobrara formation in northeast Colorado. Noble Energy plans to drill up to 235 development wells in the Niobrara Trend in 2005. The 2005 program is now underway with three drilling rigs currently operating in the area.

 

24



 

During 2004, the Company’s domestic division continued to make progress on significant deepwater developments in the Gulf of Mexico that are expected to add substantial new production through 2006:

 

                  Swordfish (Viosca Knoll 917, 961 and 962) - well completions have been finished, with production expected to commence from three wells in the second quarter of 2005 at an initial rate of approximately 10,000 Boepd, net to the Company. Noble Energy has a 60 percent working interest in Swordfish.

 

                  Lorien (Green Canyon 199) - an appraisal well is currently underway, with production expected to commence in the first half of 2006 at an initial rate of approximately 12,000 Boepd, net to the Company. Noble Energy has a 60 percent working interest in Lorien.

 

                  Ticonderoga (Green Canyon 768) - successful exploration results were announced in April 2004, with production expected to commence by mid-2006 at an initial rate of approximately 10,000 to 12,000 Boepd, net to the Company. Noble Energy has a 50 percent working interest in Ticonderoga.

 

Production from Main Pass 293/305/306 in the Gulf of Mexico remains shut in as a result of damage caused by Hurricane Ivan during September 2004. Estimated shut-in production totaled 3,500 Boepd during fourth quarter 2004 and 2,900 Boepd during third quarter 2004. The effect on total year 2004 production was 1,870 Boepd. The Company believes it has insurance coverage in an amount sufficient to make necessary repairs in order to re-establish production at Main Pass. Costs related to clean-up and redevelopment are insured to a limit that the Company believes will allow for restoration of production. The loss of production is not covered by business interruption insurance.

 

International – During 2002 and 2003, the Company completed major, capital-intensive projects in Ecuador, China, Israel and the Phase 2A expansion, the first phase of a two-phase project in Equatorial Guinea. With these important projects completed, international capital commitments declined. During 2003 and 2004, these projects contributed significantly to the Company’s financial and operating results. The Phase 2B expansion in Equatorial Guinea is underway and is scheduled to be completed during 2005. The Phase 2B expansion is expected to increase both LPG and condensate production. The project includes increasing processing capacity, storage and offloading facilities at the existing LPG plant.

 

During 2004, international production volumes increased 12,098 Boepd, or 37 percent, compared to last year, primarily from increased production in Equatorial Guinea, due to the continued ramp-up of the Phase 2A expansion project, and the commencement of natural gas sales in Israel. International operations also benefited from higher realized commodity prices. During 2004, Noble Energy participated in 95 gross international exploration and development wells, of which 92 were successful.

 

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

 

The preparation of the consolidated financial statements requires management of the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. When alternatives exist among various accounting methods, the choice of accounting method can have a significant impact on reported amounts. The following is a discussion of the Company’s accounting policies, estimates and judgments which management believes are most significant in its application of generally accepted accounting principles used in the preparation of the consolidated financial statements.

 

Reserves – All of the reserve data in this Form 10-K are estimates. The Company’s estimates of crude oil and natural gas reserves are prepared by the Company’s engineers in accordance with guidelines established by the SEC. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered. Estimates of proved crude oil and natural gas reserves significantly affect the Company’s depreciation, depletion and amortization (“DD&A”) expense. For example, if estimates of proved reserves decline, the

 

25



 

Company’s DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could also trigger an impairment analysis and could result in an impairment charge.

 

SEC guidelines do not limit reserve bookings to only contracted volumes if it can be demonstrated that there is reasonable certainty that a market exists. The Company has booked reserves in excess of contracted volumes for Israel due to the reasonable certainty of the existence of markets in future periods. In Israel, the Company has a natural gas contract with IEC, which is expected to run through 2014, and a contract with the Israel Bazan Refinery through the year 2015. The Israeli natural gas market, as estimated by the Israeli Ministry of National Infrastructure, from 2005 to 2020, is significantly greater than Noble Energy’s uncontracted net estimated proved reserves.

 

Oil and Gas Properties – The Company accounts for its crude oil and natural gas properties under the successful efforts method of accounting. The alternative method of accounting for crude oil and natural gas properties is the full cost method. Under the successful efforts method, costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties are amortized to operations by the unit-of-production method based on proved developed crude oil and natural gas reserves on a property-by-property basis as estimated by Company engineers. Application of the successful efforts method results in the expensing of certain costs including geological and geophysical costs, exploratory dry holes and delay rentals, during the periods the costs are incurred. Under the full cost method, these costs are capitalized as assets and charged to earnings in future periods as a component of DD&A expense. The Company believes the successful efforts method is the most appropriate method to use to account for its crude oil and natural gas production activities because during periods of active exploration, this method results in a more conservative measurement of net assets and net income. If the Company had used the full cost method, its financial position and results of operations would have been significantly different.

 

Exploratory Well Costs – In accordance with the successful efforts method of accounting, the costs associated with drilling an exploratory well (including costs in work-in-progress and suspended costs on go-forward projects) may be capitalized temporarily, or “suspended,” pending a determination of whether commercial quantities of crude oil or natural gas have been discovered. Except as noted below, the Company does not capitalize the costs associated with drilling an exploratory well for more than one year following completion of drilling unless the exploratory well finds crude oil and natural gas reserves in an area requiring a major capital expenditure and (1) the well has found sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made and (2) drilling of the additional exploratory wells is under way or firmly planned for the near future. For certain capital-intensive deepwater Gulf of Mexico or international projects, it may take the Company more than one year to evaluate the future potential of the exploration well and make a determination of its economic viability. The Company’s ability to move forward on a project may be dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval, the timing of which is beyond the Company’s control. In such cases, exploratory well costs remain suspended as long as the Company is actively pursuing such permits and approvals and believes they will be obtained.  Management continuously monitors suspended exploratory well costs until a decision can be made that the well has found proved reserves or is noncommercial and is impaired. These costs may be charged to exploration expense in future periods if the Company decides not to pursue additional exploratory or development activities. At December 31, 2004, the balance of property, plant and equipment included $62.7 million of suspended exploratory well costs, of which $17.7 million had been capitalized for a period greater than one year. The wells relating to these suspended costs continue to be evaluated by various means including additional seismic work, drilling additional wells or evaluating the potential of the exploration wells. For more information, see “Note 5 - Capitalized Exploratory Well Costs” of this Form 10-K.

 

Impairment of Oil and Gas Properties – The Company assesses proved crude oil and natural gas properties for possible impairment when events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. The Company recognizes an impairment loss as a result of a triggering event and when the estimated undiscounted future cash flows from a property are less than the current net book value. Estimated future cash flows are based on management’s expectations for the future and include estimates of crude oil and natural gas reserves and future commodity prices and operating costs. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and

 

26



 

could indicate a property impairment. The Company recorded $9.9 million of impairments in 2004, primarily related to downward reserve revisions on two domestic properties. The Company recorded $31.9 million of impairments in 2003, primarily related to a reserve revision on a property in the Gulf of Mexico after recompletion and remediation activities produced less-than-expected results.

 

The Company also performs periodic assessments of individually significant unproved crude oil and natural gas properties for impairment. Management’s assessment of the results of exploration activities, estimated future commodity prices and operating costs, availability of funds for future activities and the current and projected political climate in areas in which the Company operates impact the amounts and timing of impairment provisions.

 

Asset Retirement Obligation – The Company’s asset retirement obligations (“ARO”) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with its oil and gas properties. Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations,” requires that the discounted fair value of a liability for an ARO be recognized in the period in which it is incurred with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The recognition of an ARO requires that management make numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; inflation rates; and future advances in technology. In periods subsequent to initial measurement of the ARO, the Company must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A. At December 31, 2004, the Company’s balance sheet included a liability for ARO of $255.0 million, including $130.0 million for damage caused by Hurricane Ivan.

 

Derivative Instruments and Hedging Activities – The Company uses various derivative instruments to hedge its exposure to price risk from changing commodity prices. Except for NEMI’s use of derivative instruments in connection with its purchases and sales of third-party production to lock in profits or limit exposure to natural gas price risk, the Company does not enter into derivative or other financial instruments for trading purposes. Management exercises significant judgment in determining types of instruments to be used, production volumes to be hedged, prices at which to hedge and the counterparties and the hedging counterparties’ creditworthiness. The Company accounts for its derivative instruments under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. For derivative instruments that qualify as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in accumulated other comprehensive income (“AOCI”) until the forecasted transaction is recognized in earnings. Therefore, prior to settlement of the derivative instruments, changes in the fair market value of those derivative instruments can cause significant increases or decreases in AOCI. For derivative instruments that do not qualify as cash flow hedges, changes in fair value must be reported in the current period, rather than in the period in which the forecasted transaction occurs. This may result in significant increases or decreases in current period net income. All hedge ineffectiveness is recognized in the current period in net income.

 

Income Taxes – The Company is subject to income and other taxes in numerous taxing jurisdictions worldwide. For financial reporting purposes, the Company provides taxes at rates applicable for the appropriate tax jurisdictions. Estimates of amounts of income tax to be recorded involve interpretation of complex tax laws, including the recently enacted American Jobs Creation Act of 2004, and assessment of the effects of foreign taxes on domestic taxes.

 

The Company’s balance sheet includes deferred tax assets related to deductible temporary differences and operating loss carryforwards. Ultimately, realization of a deferred tax benefit depends on the existence of sufficient taxable income within the future periods to absorb future deductible temporary differences or loss carryforwards. In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. As a result of management’s assessment during 2004, the Company decreased the valuation allowances associated with certain foreign loss

 

27



 

carryforwards from $14.5 million at December 31, 2003 to zero December 31, 2004. The Company will continue to monitor facts and circumstances in its reassessment of the likelihood that operating loss carryforwards and other deferred tax assets will be utilized prior to their expiration. As a result, the Company may determine that a deferred tax asset valuation allowance should be established. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense.

 

For a discussion of the effect on the Company of the American Jobs Creation Act of 2004, see “Impact of Recently Issued Accounting Pronouncements” of this Form 10-K.

 

Pension Plan – The Company sponsors a defined benefit pension plan and other postretirement benefit plans. The actuarial determination of the projected benefit obligation and related benefit expense requires that certain assumptions be made regarding such variables as expected return on plan assets, discount rates, rate of compensation increase, estimated employee turnover rates and retirement dates, lump-sum election rates, mortality rate, retiree utilization rates for health care services and health care cost trend rates. The selection of assumptions requires considerable judgment concerning future events and has a significant impact on the amount of the obligation recorded on the Company’s balance sheets and on the amount of expense included on the Company’s statements of operations, as well as on funding.

 

Noble Energy bases its determination of the asset return component of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of December 31, 2004, the Company had cumulative asset losses of approximately $2.2 million, which remain to be recognized in the calculation of the market-related value of assets.

 

The Company utilizes the services of an outside actuarial firm to assist in the calculations of the projected benefit obligation and related costs. The Company and its actuaries use historical data and forecasts to determine assumptions. In selecting the assumption for expected long-term rate of return on assets, the Company considers the average rate of earnings expected on the funds to be invested to provide for plan benefits. This includes considering the plan’s asset allocation, historical returns on these types of assets, the current economic environment and the expected returns likely to be earned over the life of the plan. It is assumed that the long-term asset mix will be consistent with the target asset allocation of 70 percent equity and 30 percent fixed income, with a range of plus or minus 10 percent acceptable degree of variation in the plan’s asset allocation. The discount rate is determined by analyzing the interest rates implicit in current annuity contract prices and available yields on high quality fixed income securities. By definition, discount rates reflect rates at which pension benefits could be effectively settled. A one percent decrease in the expected return on plan assets assumption would have increased 2004 benefit expense by $.8 million.

 

The expected return assumption for 2005 is 8.5 percent and the assumed discount rate for 2005 is 6.0 percent. The expected return assumption was the same as 2004 and the assumed discount rate was 6.25 percent for 2004.

 

LIQUIDITY AND CAPITAL RESOURCES

 

Overview

 

The Company’s primary cash needs are to fund capital expenditures related to the acquisition, exploration and development of crude oil and natural gas properties, to repay outstanding borrowings or to pay other contractual commitments, for interest payments on debt, to pay cash dividends on common stock and to fund contributions to the Company’s pension and postretirement benefit plans. The Company’s traditional sources of liquidity are its cash on hand, cash flows from operations and available borrowing capacity under its credit facilities. Funds may also be generated from occasional sales of non-strategic crude oil and natural gas properties. The Company made significant progress during 2003 and 2004 in improving liquidity and financial flexibility. Reduction in international capital

 

28



 

commitments due to completion of major capital-intensive projects has increased flexibility and liquidity in 2004. With these projects completed or nearing completion, international capital commitments have declined while, at the same time, they have begun to contribute to the Company’s financial and operating results. A new $400 million credit facility will also provide increased liquidity in 2005.

 

The Company achieved a reduction in its ratio of debt-to-book capital (defined as the Company’s total debt divided by the sum of total debt plus equity) to 38 percent at December 31, 2004, compared to 46 percent at December 31, 2003. The Company reduced outstanding debt by $48.7 million during 2004.

 

The Company’s current ratio (current assets divided by current liabilities) was 1.10:1 at December 31, 2004, compared with .73:1 at December 31, 2003. The improvement in the current ratio in 2004, as compared to 2003, resulted primarily from a $117.4 million increase in the year-end balance of cash and cash equivalents, and a $153.7 million decrease in current installments of long-term debt. In addition, the year-end balance of accounts receivable-trade increased by $103.5 million due primarily to increases of $59.2 million for gas sales at NEMI, $17.6 million for joint operations receivables, $13.0 million for crude oil and natural gas accruals in the U.S. and U.K. and $8.3 million for electricity sales in Ecuador.

 

Cash Flows

 

Operating Activities – The Company reported a $105.4 million year-over-year increase in cash flows from operating activities. Net cash provided by operating activities totaled $708.2 million for the year ended December 31, 2004, compared to $602.8 million in 2003 and $507.0 million in 2002. The increases for 2004 and 2003 were driven by overall production increases, higher realized commodity prices and higher distributions from the Company’s unconsolidated methanol subsidiary.

 

Investing Activities – Net cash used in investing activities totaled $588.1 million, $444.8 million and $577.5 million for the years ending December 31, 2004, 2003 and 2002, respectively. The Company’s investing activities relate primarily to expenditures made for the exploration and development of oil and gas properties. Expenditures were offset by the receipt of $62.5 million, $81.1 million and $20.4 million from sales of assets during 2004, 2003 and 2002, respectively.

 

Financing Activities – Net cash provided by/(used in) financing activities totaled ($2.7) million, ($111.0) million and $12.8 million for the years ending December 31, 2004, 2003 and 2002, respectively. Financing activities consist primarily of proceeds from and repayments of bank or other long-term debt, repayment of notes payable, the payment of cash dividends and proceeds from the exercise of stock options. During 2004, the Company had a net $48.7 million reduction in outstanding debt. In addition, the Company received $62.6 million from the exercise of stock options.

 

Capital Expenditures

 

Selected capital expenditures incurred in oil and gas activities, acquisitions and downstream projects consisted of the following:

 

 

 

Year Ended December 31,

 

(in thousands)

 

2004

 

2003

 

2002

 

Oil and gas mineral interests, equipment and facilities

 

$

501,119

 

$

481,236

 

$

505,464

 

Proved property acquisition costs

 

85,785

 

1,294

 

7,988

 

Unproved property acquisition costs

 

44,681

 

10,234

 

30,515

 

Downstream projects

 

970

 

45,134

 

57,646

 

 

Total capital expenditures during 2004 increased $133.5 million, or 25 percent, as compared with 2003. The increase included costs related to the acquisition of deepwater Gulf of Mexico interests and costs expended in further development of the Amistad gas field in Ecuador. Capital expenditures during 2003 declined $68.4 million or 11

 

29



 

percent from 2002. This decrease in spending was the result of declining capital commitments due to the completion, or near completion, of major capital-intensive projects in international locations.

 

Capital expenditures, as included in investing activities in the consolidated statements of cash flows, and the capital expenditures budget were as follows:

 

 

 

Year Ended December 31,

 

(in thousands)

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Capital expenditures from investing activities

 

$

660,851

 

$

527,386

 

$

595,739

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures budget

 

$

750,000

 

$

510,000

 

$

519,000

 

 

Capital expenditures during 2004 were lower than budgeted amounts due to timing of capital outlays, which were delayed until 2005, for certain projects in the Gulf of Mexico, the United Kingdom, Israel and Phase 2B in Equatorial Guinea. Capital spending in excess of budget for 2003 was primarily due to the acceleration of the initial costs to begin the Phase 2B expansion in Equatorial Guinea. During 2002, additional capital expenditures were for the completion of the natural gas-to-power project in Ecuador and the continued development of the Israel project.

 

2005 Budget – The Company has budgeted capital expenditures of $735.0 million for 2005. Approximately 30 percent of the 2005 capital budget has been allocated for exploration opportunities, and 70 percent has been dedicated to production, development and other projects. Domestic spending is budgeted at $485.0 million (66 percent of the worldwide 2005 capital budget), international expenditures are budgeted at $228.0 million (31 percent) and corporate expenditures are budgeted at $22.0 million (three percent). The 2005 budget does not include the impact of Noble Energy’s possible asset purchases or the previously announced proposed merger with Patina.

 

The Company expects that its 2005 capital expenditure budget will be funded primarily from cash flows from operations. The Company will evaluate its level of capital spending throughout the year based upon drilling results, commodity prices, cash flows from operations and property acquisitions.

 

Discontinued Operations and Asset Sales

 

During 2004, the Company completed an asset disposition program, including five domestic property packages that had first been announced during July 2003. The sales price for the five property packages totaled approximately $130 million before closing adjustments. The Company’s consolidated financial statements have been reclassified for all periods presented to reflect the operations and assets of the properties being sold as discontinued operations. Income from discontinued operations was $14.9 million for the year ended December 31, 2004. The loss from discontinued operations of $6.1 million for the year ended December 31, 2003 included a $59.2 million ($38.5 million, net of tax) non-cash write-down to market value for certain of the five property packages.

 

Proceeds from asset sales totaled $62.5 million, $81.1 million and $20.4 million in 2004, 2003 and 2002, respectively. The Company believes the disposition of non-strategic properties allows it to concentrate efforts on strategic properties and reduce leverage.

 

Financing Activities

 

Debt – The Company’s debt totaled $880.3 million at December 31, 2004, all of which was long-term with maturities ranging from 2009 to 2097.

 

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The Company’s principal sources of liquidity are its credit facilities, including the following:

 

                  A $400 million credit agreement due November 30, 2006 with certain commercial lending institutions which bears facility fees of 15 to 30 basis points per annum and interest rates based upon a Eurodollar rate plus a range of 60 to 145 basis points per annum, depending upon the percentage of utilization and the Company’s credit rating. At December 31, 2004, there were no borrowings outstanding under this credit agreement.

                  A $400 million five-year credit facility due October 2009 with certain commercial lending institutions which bears facility fees of 10 to 25 basis points per annum and interest rates based upon a Eurodollar rate plus a range of 30 to 112.5 basis points per annum, depending upon the percentage of utilization and the Company’s credit rating. At December 31, 2004, there was $85.0 million borrowed against this credit agreement leaving $315.0 million of unused borrowing capacity.

 

Financial covenants on each of the $400 million credit facilities include the following: (a) the ratio of Earnings Before Interest, Taxes, Depreciation and Exploration Expense (“EBITDAX”) to interest expense for any consecutive period of four fiscal quarters ending on the last day of a fiscal quarter may not be less than 4.0 to 1.0; (b) the total debt to capitalization ratio, expressed as a percentage, may not exceed 60 percent at any time; and (c) the Company may not incur any guaranteed liabilities in respect of any funded indebtedness of any unrestricted subsidiary in excess of $700 million in the aggregate for all such guaranteed liabilities.

 

The Company’s credit agreements are supplemented by short-term borrowings under various uncommitted credit lines used for working capital purposes. The uncommitted credit lines may be offered by certain banks from time to time at rates negotiated at the time of borrowing.

 

Debt Issuances – During April 2004, the Company closed an offering of $200 million senior unsecured notes receiving net proceeds of approximately $197.7 million, after deducting underwriting discounts and expenses. The notes mature April 15, 2014 and pay interest semi-annually at 5.25 percent. The net proceeds from the offering were used to repay amounts outstanding under the credit agreements and for general corporate purposes.

 

During first quarter 2004, a subsidiary of the Company, Noble Energy Mediterranean, Ltd., entered into term loan agreements with several commercial lending institutions for a total of $150 million. The interest rates on the borrowings are based upon a Eurodollar rate plus an effective range of 60 to 130 basis points depending upon the Company’s credit rating. The Term Loans expire in January 2009. Proceeds were used to reduce amounts outstanding under the credit agreements.

 

Debt Repayments – During 2004, the Company repaid the following:

 

                  $125 million AMCCO Series A-2 Notes due December 2004. In connection with the repayment, the Company recognized a loss of $2.9 million ($1.9 million after tax), which is included in interest expense on the Company’s consolidated statements of operations. The repayment of the Notes was funded with borrowings under the Company’s credit facility.

                  $7.9 million on an acquisition note and $20.7 million of Israel debt.

 

The Company made cash interest payments of $46.6 million, $46.0 million and $47.6 million during 2004, 2003 and 2002, respectively.

 

Dividends – The Company paid quarterly cash dividends of four cents per share from 1989 through the third quarter 2003. For fourth quarter 2003 and for each quarter of 2004, the Company’s Board of Directors declared a quarterly cash dividend of five cents per common share. The amount of future dividends will be determined on a quarterly basis at the discretion of the Company’s Board of Directors and will depend on earnings, financial condition, capital requirements and other factors.

 

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Exercise of Stock Options – The Company received $62.6 million, $24.7 million and $7.7 million from the exercise of stock options during 2004, 2003 and 2002, respectively. Proceeds received by the Company from the exercise of stock options fluctuate primarily based on the price at which the Company’s common stock trades on the NYSE in relation to the exercise price of the options issued. During 2004, the Company’s stock reached higher sales prices than during 2003 or 2002, resulting in the exercise of more options and more proceeds to the Company.

 

Other

 

Contributions to Pension and Other Postretirement Benefit Plans – The Company made contributions of  $4.8 million to its pension and other postretirement benefit plans during 2004, $14.6 million during 2003 and $10.9 million during 2002. The Company expects to make cash contributions of $12.3 million to its pension plan during 2005. During 2004, the actual return on plan assets was a positive $7.9 million, while the returns in 2003 and 2002 were a positive $7.6 million and a negative $3.5 million, respectively. The value of the plan assets has tended to follow market performance. The expected return assumption for 2005 is 8.5 percent and the assumed discount rate for 2005 is 6.0 percent. The expected return assumption was the same as 2004. The assumed discount rate was 6.25 percent for 2004. The decrease in discount rate from 6.25 percent to 6.0 percent results in an increase in projected benefit obligation of $4.0 million. A one percent decrease in the expected return on plan assets would have resulted in an increase in benefit expense of $.8 million in 2004.

 

Federal Income Taxes – The Company made cash payments for federal income taxes of $112.3 million during 2004 and $55.5 million during 2003. During 2002, the Company received a federal tax refund of $40.4 million. The refund related to large estimated tax payments made during the first half of 2001 followed by a period of declining commodity prices, which resulted in lower taxable income by the end of 2001.

 

Contingencies – During 2004, no significant payments were made to settle any of the Company’s legal proceedings. During 2003, the Company paid $1.9 million in settlement of two legal proceedings conducted in the ordinary course of business. During 2002, the Company paid $7.0 million in settlement of a legal proceeding conducted in the ordinary course of business. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters, as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

 

Contractual Obligations

 

The following table summarizes the Company’s contractual obligations as of December 31, 2004.

 

(in thousands)
Contractual
Obligations

 

Payments Due by Period

 

Total

 

Less Than
1 Year

 

1 to 3
Years

 

4 to 5
Years

 

After 5
Years

 

Outstanding debt

 

$

885,000

 

$

 

 

$

 

 

$

235,000

 

$

650,000

 

Asset retirement obligations (1)

 

254,983

 

79,568

 

91,115

 

14,330

 

69,970

 

Derivative instruments

 

59,982

 

50,304

 

9,662

 

16

 

 

 

Building lease

 

11,647

 

1,588

 

3,176

 

3,176

 

3,707

 

Total contractual obligations

 

$

1,211,612

 

$

131,460

 

$

103,953

 

$

252,522

 

$

723,677

 

 


(1)          Asset retirement obligations are discounted.

 

In addition, in the ordinary course of business, the Company maintains letters of credit in support of certain performance obligations of its subsidiaries. Outstanding letters of credit totaled approximately $4.1 million at December 31, 2004. For more information, see “Item 8. Financial Statements and Supplementary Data—Note 7 - Debt” of this Form 10-K.

 

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RESULTS OF OPERATIONS

 

Net Income and Revenues

 

The Company’s net income for 2004 was $328.7 million, an increase of over 300 percent compared to 2003 net income. Factors contributing to the increase included:

 

                  A 57 percent, or $209.0 million, increase in crude oil sales due to a 26 percent increase in daily production and a 25 percent increase in average realized crude oil prices;

                  A 27 percent, or $126.0 million, increase in natural gas sales due to a nine percent increase in daily production and a 15 percent increase in average realized natural gas prices;

                  A 21 percent, or $31.8 million, decrease in exploration expense; and

                  A 70 percent, or $28.5 million, increase in income from unconsolidated subsidiaries.

 

Natural Gas Information

 

Natural gas revenues increased 27 percent in 2004 compared to 2003 due to a 15 percent increase in average realized natural gas prices and a nine percent increase in daily natural gas production. Natural gas revenues increased 35 percent in 2003, compared to 2002, due to a 43 percent increase in natural gas prices, offset by a one percent decrease in daily natural gas production.

 

 

 

Year Ended December 31,

 

(in thousands)

 

2004

 

2003