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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2002

OR

For the transition period from                      to                      

Commission file number 1-8590

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (870) 862-6411

Securities registered pursuant to Section 12(b) of the Act:

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, and (2) has been subject to such filing requirements for the past 90 days. Yes  þ No  ¨.

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of 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.  þ

Aggregate market value of the voting stock held by non-affiliates of the registrant, based on average price at January 31, 2003, as quoted by the New York Stock Exchange, was approximately $2,924,876,000.

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

Aggregate market value of the voting stock held by non-affiliates of the registrant, based on average price at June 28, 2002, as quoted by the New York Stock Exchange, was approximately $2,894,828,000.

Number of shares of Common Stock, $1.00 Par Value, outstanding at January 31, 2003 was 91,699,376.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the Registrant’s definitive Proxy Statement relating to the Annual Meeting of Stockholders on May 14, 2003 have been incorporated by reference in Part III herein.

Table of Contents

MURPHY OIL CORPORATION

TABLE OF CONTENTS – 2002 FORM 10-K

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PART I

Items 1. and 2. BUSINESS AND PROPERTIES

Summary

Murphy Oil Corporation is a worldwide oil and gas exploration and production company with refining and marketing operations in North America and the United Kingdom. As used in this report, the terms Murphy, Murphy Oil, we, our, its and Company may refer to Murphy Oil Corporation or any one or more of its consolidated subsidiaries.

The Company was originally incorporated in Louisiana in 1950 as Murphy Corporation. It was reincorporated in Delaware in 1964, at which time it adopted the name Murphy Oil Corporation, and was reorganized in 1983 to operate primarily as a holding company of its various businesses. Its operations are classified into two business activities: (1) “Exploration and Production” and (2) “Refining and Marketing.” For reporting purposes, Murphy’s exploration and production activities are subdivided into six geographic segments, including the United States, Canada, the United Kingdom, Ecuador, Malaysia and all other countries. Murphy’s refining and marketing activities are presently subdivided into geographic segments for North America and United Kingdom. Canadian pipeline and trucking operations were sold in May 2001. Additionally, “Corporate and Other Activities” include interest income, interest expense and overhead not allocated to the segments.

The information appearing in the 2002 Annual Report to Security Holders (2002 Annual Report) is incorporated in this Form 10-K report as Exhibit 13 and is deemed to be filed as part of this Form 10-K report as indicated under Items 1, 2 and 7. A narrative of the graphic and image information that appears in the paper format version of Exhibit 13 is included in the electronic Form 10-K document as an appendix to Exhibit 13.

In addition to the following information about each business activity, data about Murphy’s operations, properties and business segments, including revenues by class of products and financial information by geographic area, are provided on pages 8 through 17, F-13, F-29 through F-31, F-35 through F-37, and F-39 of this Form 10-K report and on pages 4 through 12 of the 2002 Annual Report.

Interested parties may access the Company’s public disclosures filed with the Securities and Exchange Commission, including Form 10-K, Form 10-Q, Form 8-K and other documents, by accessing the Investor Relations section of Murphy Oil Corporation’s website at www.murphyoilcorp.com.

Exploration and Production

During 2002, Murphy’s principal exploration and production activities were conducted in the United States, Ecuador and Malaysia by wholly owned Murphy Exploration & Production Company (Murphy Expro) and its subsidiaries, in western Canada and offshore eastern Canada by wholly owned Murphy Oil Company Ltd. (MOCL) and its subsidiaries, and in the U.K. North Sea and the Atlantic Margin by wholly owned Murphy Petroleum Limited. Murphy’s crude oil and natural gas liquids production in 2002 was in the United States, Canada, the United Kingdom and Ecuador; its natural gas was produced and sold in the United States, Canada and the United Kingdom. MOCL owns a 5% interest in Syncrude Canada Ltd., which utilizes its assets to extract bitumen from oil sand deposits in northern Alberta and to upgrade this bitumen into synthetic crude oil.

Murphy’s estimated net quantities of proved oil and gas reserves and proved developed oil and gas reserves at December 31, 1999, 2000, 2001 and 2002 by geographic area are reported on pages F-33 and F-34 of this Form 10-K report. Murphy has not filed and is not required to file any estimates of its total net proved oil or gas reserves on a recurring basis with any federal or foreign governmental regulatory authority or agency other than the U.S. Securities and Exchange Commission. Annually, Murphy reports gross reserves of properties operated in the United States to the U.S. Department of Energy; such reserves are derived from the same data from which estimated net proved reserves of such properties are determined.

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Net crude oil, condensate, and gas liquids production and sales, and net natural gas sales by geographic area with weighted average sales prices for each of the five years ended December 31, 2002 are shown on page 13 of the 2002 Annual Report.

Production expenses for the last three years in U.S. dollars per equivalent barrel are discussed on page 14 of this Form 10-K report. For purposes of these computations, natural gas sales volumes are converted to equivalent barrels of crude oil using a ratio of six thousand cubic feet (MCF) of natural gas to one barrel of crude oil.

Supplemental disclosures relating to oil and gas producing activities are reported on pages F-32 through F-39 of this Form 10-K report.

At December 31, 2002, Murphy held leases, concessions, contracts or permits on developed and undeveloped acreage as shown by geographic area in the following table. Gross acres are those in which all or part of the working interest is owned by Murphy; net acres are the portions of the gross acres applicable to Murphy’s working interest.

The only significant undeveloped acreage that expires in the next three years is approximately 2.4 million acres in shallow-water Blocks SK 309 and SK 311 in Malaysia that is not included in the West Patricia discovery area. The Company is currently negotiating to extend the exploration rights for this acreage.

As used in the three tables that follow, “gross” wells are the total wells in which all or part of the working interest is owned by Murphy, and “net” wells are the total of the Company’s fractional working interests in gross wells expressed as the equivalent number of wholly owned wells.

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The following table shows the number of oil and gas wells producing or capable of producing at December 31, 2002.

Murphy’s net wells drilled in the last three years are shown in the following table.

Murphy’s drilling wells in progress at December 31, 2002 are shown below.

Additional information about current exploration and production activities is reported on pages 4 through 9 of the 2002 Annual Report.

Refining and Marketing

Murphy Oil USA, Inc. (MOUSA), a wholly owned subsidiary, owns and operates two refineries in the United States. The Meraux, Louisiana refinery is located on fee land and on two leases that expire in 2010 and 2021, at which times the Company has options to purchase the leased acreage at fixed prices. The refinery at Superior, Wisconsin is located on fee land. Murco Petroleum Limited (Murco), a wholly owned U.K. subsidiary serviced by Murphy Eastern Oil Company, has an effective 30% interest in a refinery at Milford Haven, Wales that can process 108,000 barrels of crude oil a day. Refinery capacities at December 31, 2002 are shown in the following table.

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The Company is in the process of expanding the Meraux refinery, with the expansion scheduled to be completed and operational by the fourth quarter 2003. The expansion will allow the refinery to meet new low-sulfur product specifications which become effective in 2006. The expansion includes a new hydrocracker unit, central control room and two new utility boilers; expansion of the crude oil processing capacity from 100,000 barrels per stream day (b/sd) to 125,000 b/sd, expansion of naphtha hydrotreating capacity from 22,000 b/sd to 35,000 b/sd, and expansion of the catalytic reforming capacity from 18,000 b/sd to 32,000 b/sd; and construction of a new sulfur recovery complex, including amine regeneration, sour water stripping and high efficiency sulfur recovery.

MOUSA markets refined products through a network of retail gasoline stations and branded and unbranded wholesale customers in a 23-state area of the southern and midwestern United States. Murphy’s retail stations are primarily located in the parking areas of Wal-Mart stores in 21 states and use the brand name Murphy USA^®. Branded wholesale customers use the brand name SPUR^®. Refined products are supplied from 11 terminals that are wholly owned and operated by MOUSA, 16 terminals that are jointly owned and operated by others, and numerous terminals owned by others. Of the terminals wholly owned or jointly owned, four are supplied by marine transportation, three are supplied by truck, two are adjacent to MOUSA’s refineries and 18 are supplied by pipeline. MOUSA receives products at the terminals owned by others either in exchange for deliveries from the Company’s terminals or by outright purchase. At December 31, 2002, the Company marketed products through 506 Murphy USA stations and 402 branded wholesale SPUR stations. MOUSA plans to add about 100 new Murphy USA stations at Wal-Mart sites in the southern and midwestern United States in 2003. In February 2002, the Company and Wal-Mart reached an agreement for a Canadian subsidiary of the Company to market products through Murphy Canada^™ stations at select Wal-Mart stores across Canada. The Company’s subsidiary operates six stations at Wal-Mart sites in Canada at December 31, 2002. An additional seven Murphy Canada stations are expected to be added in 2003.

Murphy has master agreements that allow the Company to rent space in the parking lots of Wal-Mart stores in 21 states and in Canada for the purpose of building retail gasoline stations. The master agreements contain general terms applicable to all sites in the United States and Canada. As each individual station is constructed, an addendum to each master agreement is entered into, which contains the terms specific to that location. The terms of the agreements range from 10-15 years at each station, with Murphy holding two successive five-year extension options at each site. The agreements permit Wal-Mart to terminate the agreements in their entirety, or only as to affected sites, at its option for the following reasons: Murphy vacates or abandons the property; Murphy improperly transfers the rights under this agreement to another party; an agreement or a premises is taken upon execution or by process of law; Murphy files

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a petition in bankruptcy or becomes insolvent; Murphy fails to pay its debts as they become due; Murphy fails to pay rent or other sums required to be paid within 90 days after written notice; or Murphy fails to perform in any material way as required by the agreements. Sales from these stations amounted to 30.3% of total Company revenues in 2002, 22.5% in 2001 and 14.6% in 2000. As the Company continues to expand the number of gasoline stations at Wal-Mart sites, total revenue generated by this business is expected to grow proportionately.

At the end of 2002, Murco distributed refined products in the United Kingdom from the Milford Haven refinery, three wholly owned terminals supplied by rail, six terminals owned by others where products are received in exchange for deliveries from the Company’s terminals, and 416 branded stations under the brand names MURCO and EP.

Murphy owns a 20% interest in a 120-mile refined products pipeline, with a capacity of 165,000 barrels a day, that transports products from the Meraux refinery to two common carrier pipelines serving the southeastern United States. The Company also owns a 3.2% interest in LOOP LLC, which provides deepwater unloading accommodations off the Louisiana coast for oil tankers and onshore facilities for storage of crude oil. A crude oil pipeline with a diameter of 24 inches connects LOOP storage at Clovelly, Louisiana to the Meraux refinery. Murphy owns 29.4% of the first 22 miles of this pipeline from Clovelly to Alliance, Louisiana and 100% of the remaining 24 miles from Alliance to Meraux. The pipeline is connected to another company’s pipeline system, allowing crude oil transported by that system to also be shipped to the Meraux refinery. In February 2002, the Company sold its 22% interest in a 312-mile crude oil pipeline in Montana and Wyoming for $7 million.

In May 2001, the Company sold its Canadian pipeline and trucking operation, including seven crude oil pipelines with various ownership percentages and capacities. Murphy realized an after-tax gain of $71 million on this sale.

Additional information about current refining and marketing activities and a statistical summary of key operating and financial indicators for each of the five years ended December 31, 2002 are reported on pages 10, 11 and 14 of the 2002 Annual Report.

Employees

At December 31, 2002, Murphy had 4,010 employees – 1,980 full-time and 2,030 part-time.

Competition and Other Conditions Which May Affect Business

Murphy operates in the oil industry and experiences intense competition from other oil companies, which include state-owned foreign oil companies, major integrated oil companies, independent producers of oil and natural gas and independent refining companies. Virtually all of the state-owned and major integrated oil companies and many of the independent producers and independent refiners that compete with the Company have substantially greater resources than Murphy. In addition, the oil industry as a whole competes with other industries in supplying energy requirements around the world. Murphy is a net purchaser of crude oil and other refinery feedstocks, and also purchases refined products, particularly gasoline needed to supply its retail marketing stations located at Wal-Mart sites. The Company may be required to respond to operating and pricing policies of others, including producing country governments from whom it makes purchases. Additional information concerning current conditions of the Company’s business is reported under the caption “Outlook” beginning on page 22 of this Form 10-K report.

In 2002, the Company’s production of oil and natural gas represented approximately 0.1% of the respective worldwide totals. Murphy owned approximately 0.8% of the crude oil refining capacity in the United States and its market share of U.S. retail gasoline sales was approximately 0.8%.

The operations and earnings of Murphy have been and continue to be affected by worldwide political developments. Many governments, including those that are members of the Organization of Petroleum Exporting Countries (OPEC), unilaterally intervene at times in the orderly market of crude oil and natural gas produced in their countries through such actions as setting prices, determining rates of production, and controlling who may buy and sell the production.

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In addition, prices and availability of crude oil, natural gas and refined products could be influenced by political unrest and by various governmental policies to restrict or increase petroleum usage and supply. Other governmental actions that could affect Murphy’s operations and earnings include tax changes and regulations concerning: currency fluctuations, protection and remediation of the environment (See the caption “Environmental” beginning on page 17 of this Form 10-K report), preferential and discriminatory awarding of oil and gas leases, restrictions on drilling and/or production, restraints and controls on imports and exports, safety, and relationships between employers and employees. Because these and other factors too numerous to list are subject to constant changes caused by governmental and political considerations and are often made in great haste in response to changing internal and worldwide economic conditions and to actions of other governments or specific events, it is not practical to attempt to predict the effects of such factors on Murphy’s future operations and earnings.

Murphy’s business is subject to operational hazards and risks normally associated with the exploration for and production of oil and natural gas and the refining and marketing of crude oil and petroleum products. The occurrence of an event, including but not limited to acts of nature, mechanical equipment failures, industrial accidents, fires and intentional attacks could result in the loss of hydrocarbons and associated revenues, environmental pollution or contamination, and personal injury or bodily injury, including death, for which the Company could be deemed to be liable, and could subject the Company to substantial fines and/or claims for punitive damages. Murphy maintains insurance against certain, but not all, hazards that could arise from its operations, and such insurance is believed to be reasonable for the hazards and risks faced by the Company. As of December 31, 2002, the Company maintained total excess liability insurance with limits of $500 million per occurrence covering employees, general liability and certain “sudden and accidental” environmental risks. The Company also maintained insurance coverage with an additional limit of $250 million per occurrence, all or part of which could be applicable to certain gradual and/or sudden and accidental pollution events. There can be no assurance that such insurance will be adequate to offset lost revenues or costs associated with certain events or that insurance coverage will continue to be available in the future on terms that justify its purchase. The occurrence of an event that is not fully insured could have a material adverse effect on the Company’s financial condition and results of operations in the future.

Executive Officers of the Registrant

The age at January 1, 2003, present corporate office and length of service in office of each of the Company’s executive officers are reported in the following listing. Executive officers are elected annually but may be removed from office at any time by the Board of Directors.

Claiborne P. Deming – Age 48; President and Chief Executive Officer since October 1994 and Director and Member of the Executive Committee since 1993. He served as Executive Vice President and Chief Operating Officer from 1992 to 1993 and President of MOUSA from 1989 to 1992.

W. Michael Hulse – Age 49; Executive Vice President – Worldwide Downstream Operations effective April 2003. Mr. Hulse was President of MOUSA from November 2001 to present. He served as President of Murphy Eastern Oil Company from April 1996 to November 2001.

Steven A. Cossé – Age 55; Senior Vice President since October 1994 and General Counsel since August 1991. Mr. Cossé was elected Vice President in 1993. For the eight years prior to August 1991, he was General Counsel for Ocean Drilling & Exploration Company (ODECO), a majority-owned subsidiary of Murphy.

Bill H. Stobaugh – Age 51; Vice President since May 1995, when he joined the Company. Prior to that, he had held various engineering, planning and managerial positions, the most recent being with an engineering consulting firm.

Kevin G. Fitzgerald – Age 47; Treasurer since July 2001. Mr. Fitzgerald was Director of Investor Relations from 1996 to June 2001, and also served in various capacities with the Company and ODECO between 1982 and 1996.

John W. Eckart – Age 44; Controller since March 2000. Mr. Eckart had been Assistant Controller since February 1995. He joined the Company as Auditing Manager in 1990.

Walter K. Compton – Age 40; Secretary since December 1996. He has been an attorney with the Company since 1988 and became Manager, Law Department, in November 1996.

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Item 3. LEGAL PROCEEDINGS

In December 2000, two of the Company’s Canadian subsidiaries, Murphy Oil Company Ltd. (MOCL) and Murphy Canada Exploration Company (MCEC) as plaintiffs filed an action in the Court of Queen’s Bench of Alberta seeking a constructive trust over oil and gas leasehold rights to Crown lands in British Columbia. The suit alleges that the defendants, The Predator Corporation Ltd. and Predator Energies Partnership (collectively Predator) and Ricks Nova Scotia Co. (Ricks), acquired the lands after first inappropriately obtaining confidential and proprietary data belonging to the Company and its partner. In January 2001, Ricks, representing an undivided 75% interest in the lands in question, settled its portion of the litigation by conveying its interest to the Company and its partner at cost. In 2001, Predator, representing the remaining undivided 25% of the lands in question, filed a counterclaim, as subsequently amended, against MOCL and MCEC and MOCL’s President individually seeking compensatory damages of C$4.61 billion. The Company believes that the counterclaim is without merit and that the amount of damages sought is frivolous. While the litigation is in its preliminary stages and no assurance can be given about the outcome, the Company does not believe that the ultimate resolution of this suit will have a material adverse effect on its financial condition.

Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business and none of which is expected to have a material adverse effect on the Company’s financial condition. The ultimate resolution of matters referred to in this item could have a material adverse effect on the Company’s earnings in a future period.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

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

PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

The Company’s Common Stock is traded on the New York Stock Exchange and the Toronto Stock Exchange using “MUR” as the trading symbol. There were 2,826 stockholders of record as of December 31, 2002. Information as to high and low market prices per share and dividends per share by quarter for 2002 and 2001 are reported on page F-40 of this Form10-K report.

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Item 6. SELECTED FINANCIAL DATA

Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Results of Operations

The Company reported net income in 2002 of $111.5 million, $1.21 per diluted share, compared to net income in 2001 of $330.9 million, $3.63 per share. In 2000 the Company earned $296.8 million, $3.28 per diluted share. All 2001 and 2000 earnings per share have been adjusted to reflect the two-for-one stock split effective December 30, 2002. In December 2002 the Company sold its interest in Ship Shoal Block 113 in the Gulf of Mexico for an after-tax gain of $10.6 million. In accordance with Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which the Company adopted on January 1, 2002, the results of operations for Ship Shoal Block 113 have been reflected as discontinued operations in all years presented. Therefore, the aforementioned gain on disposal of $10.6 million in 2002, and routine operating results of the field, have been included net of income tax expense as Discontinued Operations in the consolidated statements of income for the three years ended December 31, 2002. Income from continuing operations was $97.5 million in 2002, $1.06 per share; $328.4 million in 2001, $3.60 per share; and $298.5 million in 2000, $3.30 per share.

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The three year period ended December 31, 2002 included certain nonrecurring items which can obscure underlying trends of operating results and affect comparability between years. Although results excluding nonrecurring items is considered a non-GAAP measure, the Company’s management believes this information is useful in assessing Murphy Oil’s performance. Nonrecurring items reduced income from continuing operations in 2002 by $6.7 million, but increased this amount by $67.6 million in 2001 and $1.5 million in 2000. Excluding these nonrecurring items, income from continuing operations amounted to $104.2 million in 2002, $260.8 million in 2001, and $297 million in 2000. In 2000 the Company recorded a net charge of $8.7 million, $.10 per share, as the cumulative effect of an accounting change for a one-time non-cash adjustment to record crude oil revenues at the time the oil is sold rather than as it is produced.

2002 vs. 2001 – Income from continuing operations in 2002 was $97.5 million, $1.06 per share, compared to $328.4 million, $3.60 per share, in 2001. The decline in 2002 results of $230.9 million was mainly due to a $193.6 million reduction in refining and marketing results, caused by both weaker refining margins in 2002 compared to 2001 in the U.S. and U.K. and a $74.3 million reduction in income from nonrecurring items in 2002. The lower income from nonrecurring items was primarily caused by a $71 million gain in 2001 from sale of Canadian pipeline and trucking operations. Earnings from the Company’s exploration and production activities were $26.5 million lower in 2002 than in 2001 as record levels of oil and natural gas production and higher average oil prices were more than offset by lower natural gas sales prices, higher charges for property impairments and higher production and depreciation expenses.

Sales and other operating revenues were $222.5 million higher in 2002 than in 2001 due to record production and sales of crude oil and natural gas and higher sales volumes for refined products in North America and the United Kingdom. Gain on sale of assets declined by $96.4 million primarily due to the sale of Canadian pipeline and trucking assets in 2001. Interest and other income was $7.8 million lower in 2002 due to less interest earned on invested cash. Crude oil, natural gas and product purchases increased by $305.5 million in 2002 due to more purchases of finished products for retail marketing operations and a higher average purchase price for these products than in 2001. Operating expenses rose by $60.7 million mainly due to record oil and natural gas production, higher maintenance costs for oil and gas producing fields and $5 million of costs to repair uninsured damage from tropical storms in the Gulf of Mexico. Depreciation, depletion and amortization expense increased $73.4 million in 2002 due to higher oil and natural gas production and more retail marketing stations. Interest expense was $12.2 million more in 2002 due to higher average long-term borrowings than in 2001, including the sale of 10-year notes with a stated rate of 6.375% in 2002. Capitalized interest increased by $4.3 million due to ongoing projects to develop deepwater Gulf of Mexico fields, expand Syncrude, and build a hydrocracker and expand crude oil throughput capacity at the Meraux, Louisiana refinery. Income tax expense fell by $119.5 million essentially in line with lower pretax income from continuing operations.

2001 vs. 2000 – Income from continuing operations in 2001 was a company record $328.4 million, $3.60 per share, an increase of $29.9 million from the $298.5 million, $3.30 per share, earned in 2000. Record earnings in 2001 from the Company’s refining and marketing operations and greater benefits from nonrecurring items were only partially offset by lower income from exploration and production activities. Improved refining and marketing results of $99.2 million were attributable to stronger unit margins in the U.S. refining business during the first half of 2001 and a $71 million nonrecurring profit on sale of Canadian pipeline and trucking operations in May 2001. Exploration and production results declined by $58.2 million in 2001 mainly caused by an 18% reduction in realized oil prices and higher exploration expenses. These were partially offset by higher oil and natural gas production and lower charges for property impairments.

Sales and other operating revenues in 2001 increased by $113.8 million compared to 2000 due to higher oil, natural gas and refined product sales volumes. Gain on sale of assets was up by $101.5 million due to the sale in May 2001 of the Canadian pipeline and trucking operations. Interest and other income was $7.5 million lower in 2001 due to less interest earned on invested cash balances and lower interest associated with settlement of prior year tax issues. Crude oil, natural gas and product purchases were $46 million higher due to more purchases of crude oil and refined products, with this effort partially mitigated by a lower average price than in 2000. Operating expenses increased by $66.5 million due to higher oil and natural gas production and more retail gasoline stations. The increase of $31.3 million in exploration expenses is explained on page 14. Selling and general expenses increased by $12.4 million primarily due to higher salaries and benefits and legal and professional fees in 2001. Depreciation, depletion and amortization expense rose by $15.7 million due to a combination of higher oil and gas production and more retail marketing stations. Amortization of goodwill of $3.1 million related to the acquisition of Beau Canada Exploration Ltd. (Beau Canada) in

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November 2001. Impairment of properties was down by $17.4 million in 2001 due to less impairment write-downs for Gulf of Mexico and western Canada properties. Interest expense was $9.4 million higher in 2001 due to higher average borrowings during the year, primarily arising from the acquisition of Beau Canada in late 2000. Capitalized interest was $6.7 million more than in 2000 primarily due to continued development expenditures for the Terra Nova field, offshore Newfoundland. Income tax expense increased by $17.7 million in 2001 due to higher pretax earnings from continuing operations.

In the following table, the Company’s results of operations for the three years ended December 31, 2002 are presented by segment. More detailed reviews of operating results for the Company’s exploration and production and refining and marketing activities follow the table.

Nonrecurring Items – Income from continuing operations in the table above includes the following nonrecurring items, which can affect underlying trends of operating results and comparability between years. These nonrecurring items are presented net of tax below and are discussed in more detail following the tables.

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These nonrecurring items were reflected in the following segments.

The effects of nonrecurring items on quarterly results of 2002 and 2001 are presented on page F-41 of this Form 10-K report.

Exploration and Production – Earnings from exploration and production operations were $161 million in 2002, $187.5 million in 2001 and $245.7 million in 2000. The decline in 2002 was caused by a 24% lower average natural gas sales price in North America, higher costs associated with property impairments and higher production and depreciation expenses. The unfavorable effects of these items were partially offset by record production of both crude oil and natural gas and a 10% higher average sales price for crude oil and condensate. Oil production from continuing operations increased by 13% in 2002 to 75,213 barrels per day and natural gas production from continuing operations

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rose by 5% to 292.9 million cubic feet per day. Higher property impairment expense in 2002 was mostly related to the write-off of remaining costs for Destin Dome Blocks 56 and 57, offshore Florida. Based on an agreement with the U.S. government, the Company may not seek approval for development of this significant natural gas discovery in Destin Dome until at least 2012. The decline in 2001 was primarily attributable to an 18% decline in the Company’s average oil sales price compared to 2000. Additionally, exploration expenses increased over 2000, a significant portion of which were in foreign jurisdictions where the Company has no realized income tax benefits. Production of crude oil, condensate and natural gas liquids from continuing operations increased from 63,917 barrels per day in 2000 to 66,344 in 2001, a 4% increase. Natural gas sales volumes from continuing operations totaled 278.3 million cubic feet per day in 2001, up 23% from 226 million in 2000.

The results of operations for oil and gas producing activities for each of the last three years are shown by major operating areas on pages F-36 and F-37 of this Form 10-K report. Daily production and sales rates and weighted average sales prices are shown on page 13 of the 2002 Annual Report.

A summary of oil and gas revenues from continuing operations, including intersegment sales that are eliminated in the consolidated financial statements, is presented in the following table.

The Company’s crude oil, condensate and natural gas liquids production from continuing operations averaged 75,213 barrels per day in 2002, 66,344 in 2001 and 63,917 in 2000. Oil production in the United States declined 13% to 4,128 barrels per day in 2002, following an 11% decline in 2001. The reduction in both years was primarily due to declines from existing fields in the Gulf of Mexico. Oil production in Canada increased 34% in 2002 to a record volume of 48,239 barrels per day. The Terra Nova field, offshore Newfoundland, commenced production in January 2002 and averaged 12,463 barrels per day for the year. The Company’s share of net production at its synthetic oil operation improved 883 barrels per day, or 8%, in 2002 due to a combination of higher gross production and a lower net profit royalty caused by higher capital spending related to an ongoing expansion project. Before royalties, the Company’s synthetic oil production was 11,477 barrels per day in 2002, 11,157 in 2001 and 10,145 in 2000. Production of light oil decreased 982 barrels per day, or 23%, and heavy oil production decreased 19% to 9,484 barrels per day in 2002 with both decreases primarily due to declines at existing western Canada fields. Production at Hibernia rose 21% in 2002 to 11,574 barrels per day due to better operating efficiency. U.K. production was down by 1,912 barrels per day, or 9%, primarily due to declines from the Company’s “T” Block and Ninian fields in the North Sea. The Company produced 4,544 barrels of oil per day in Ecuador, 15% lower than in 2001, primarily due to further pipeline constraints on the existing oil pipeline. An additional pipeline is scheduled to commence operation in the second half of 2003.

During 2001, oil production in the United States declined 14% compared to 2000 and averaged 4,752 barrels per day. The reduction was due to declines from existing fields in the Gulf of Mexico. Oil production in Canada increased 15% in 2001 to 36,059 barrels per day. The Company’s share of net production at its synthetic oil operation improved 2,036 barrels per day, or 24%, in 2001 due to both higher gross production and a lower net profit royalty caused by increased capital spending and a lower oil price. Production of light oil increased 1,258 barrels per day, or 41%, and heavy oil production increased 11% to 11,707 barrels per day in 2001 with both increases primarily due to the Company’s acquisition of Beau Canada in November 2000. Production at Hibernia rose 4% in 2001 to 9,535 barrels per day due to

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better operating efficiency, primarily associated with improved handling of gas production. U.K. production was down by 681 barrels per day, or 3%, due to declines from the Company’s existing fields in the North Sea. Oil production in Ecuador was 17% lower than 2000 and totaled 5,319 barrels per day. This reduction was caused by more pipeline constraints, which forced the operation to limit daily production.

Worldwide sales of natural gas from continuing operations were a record 292.9 million cubic feet per day in 2002, up from 278.3 million in 2001. Natural gas sales were 226 million cubic feet per day in 2000. Sales of natural gas in the United States were 88.1 million cubic feet per day in 2002, 112.6 million in 2001 and 141.4 million in 2000. The reductions in 2002 and 2001 were due to lower deliverability from maturing fields in the Gulf of Mexico. Natural gas sales in Canada in 2002 were at record levels for the seventh consecutive year as sales increased 30% to 197.9 million cubic feet per day. Canadian natural gas sales had increased more than 100% in 2001. The increase in 2002 was primarily due to higher production from the Ladyfern field, while the 2001 increase was due to the acquisition of Beau Canada in late 2000 and from new discoveries, including Ladyfern, in western Canada. Natural gas sales in the United Kingdom were 7 million cubic feet per day in 2002, down 47% compared to 2001. U.K. natural gas sales in 2001 increased 21% compared to 2000 levels and totaled 13.1 million cubic feet per day. The lower production in 2002 was due to declines at the Amethyst field in the North Sea, while the added volumes in 2001 were attributable to higher production at both the Amethyst and Mungo/Monan fields.

The average sales price for light crude oil in 2002 was comparable to 2001; however, heavy oil prices were significantly stronger in comparison to light oil prices during the year. In the United States, the Company’s average monthly sales price for crude oil and condensate declined 3% compared to 2001 and averaged $24.25 per barrel for the year. In Canada, the sales price for light oil rose 1% to $22.60 per barrel. Heavy oil prices in Canada averaged $16.82 per barrel, up 52% from 2001. The sales price for crude oil from the Hibernia field rose 7% to $25.34 per barrel. The average sales price for oil from the new Terra Nova field was $25.38 per barrel. Synthetic oil prices in 2002 were $25.64 per barrel, up 2% from a year ago. Sales prices in the U.K. were about flat with 2001 at $24.39 per barrel and sales prices in Ecuador were up 16% to $19.64 per barrel.

Worldwide crude oil sales prices declined during 2001 compared to 2000. In the United States, the Company’s average sales price for crude oil and condensate was $24.92 per barrel for the year, down 18% compared to 2000. In Canada, sales prices for light oil fell 19% to $22.40 per barrel. Canadian heavy oil prices were down 38% from 2000 and averaged $11.06 per barrel. The sales price for Hibernia crude oil decreased 12% to $23.77 per barrel. Synthetic oil prices in 2001 averaged $25.04 per barrel, down 15% from a year ago. Sales prices in the U.K. were $24.44 per barrel, a decline of 12%, and sales prices in Ecuador were down 23% to $17.00 per barrel.

The Company’s North American natural gas sales prices were weaker during 2002 compared to 2001 due generally to a warmer than normal winter. Natural gas sales prices in North America decreased 24% from 2001 and averaged $2.94 per MCF in 2002 compared to $3.87 in the prior year. U.S. natural gas sales prices decreased 27% in 2002 and averaged $3.37 per MCF compared to $4.64 in the prior year. Canadian natural gas production was sold in 2002 at an average price of $2.74 per MCF, 16% lower than in 2001. The sales price for natural gas sold in the United Kingdom increased 10% to $2.76 per MCF.

North American natural gas sales price averaged $3.87 per MCF for the year 2001 compared to $3.90 in 2000. U.S. sales prices averaged $4.64 per MCF compared to $4.01 a year ago. However, the sales price for natural gas sold in Canada declined 11% to $3.28 per MCF. Prices in the United Kingdom increased to $2.52 per MCF from $1.81 in 2000.

Based on 2002 volumes and deducting taxes at marginal rates, each $1 per barrel and $.10 per MCF fluctuation in prices would have affected annual exploration and production earnings by $17.2 million and $5.8 million, respectively. The effect of these price fluctuations on consolidated net income cannot be measured because operating results of the Company’s refining and marketing segments could be affected differently.

Production expenses were $229.6 million in 2002, $211 million in 2001 and $176.1 million in 2000. These amounts are shown by major operating area on pages F-36 and F-37 of this Form 10-K report. Costs per equivalent barrel during the last three years excluding discontinued operations were as follows.

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The increase in the cost per equivalent barrel in the United States in both 2002 and 2001 was attributable to a combination of lower production and higher well servicing costs. Lower average costs in 2002 for Canada, excluding synthetic oil, was due to higher natural gas production volumes and new production from the Terra Nova field, offshore Newfoundland. The decrease in Canada during 2001, excluding synthetic oil, was primarily due to higher production of light oil, heavy oil and natural gas. The lower average cost per barrel for Canadian synthetic oil in 2002 was due to a combination of lower maintenance costs and higher net production, while the increased cost in 2001 was due to higher maintenance costs. The increase in average costs in the U.K. in 2002 was due to both higher costs to maintain mature properties, primarily at the Ninian field, and lower overall production. The increase in the United Kingdom during 2001 was also the result of higher costs for mature properties. Higher costs per unit in Ecuador in 2002 and 2001 were both due to lower oil production compared to the previous year.

Exploration expenses for each of the last three years are shown in total in the following table, and amounts are reported by major operating area on pages F-36 and F-37 on this Form 10-K report. Certain of the expenses are included in the capital expenditures total for exploration and production activities.

The increase in dry hole costs in 2002 was caused by higher costs for unsuccessful exploration drilling wells in the deep waters of the Gulf of Mexico and Malaysia, which were offset in part by lower costs in 2002 for wells off the east coast of Canada. Dry hole costs were higher in 2001 than in 2000 as more unsuccessful drilling costs off the east coast of Canada were partially offset by lower costs in the deepwater Gulf of Mexico. Geological and geophysical costs were down in 2002 due to less spending for 3-D seismic on deepwater concessions in Malaysia. Other exploration expenses were lower in 2002 primarily due to more recoveries from the Company’s partner in Malaysia. Undeveloped leasehold amortization increased in 2001 compared to 2000 primarily because of lease acquisitions in western Canada.

Depreciation, depletion and amortization expense related to exploration and production operations totaled $247.2 million in 2002, $181.1 million in 2001 and $166.6 million in 2000. Higher costs in 2002 were caused by record oil and natural gas production, including start up of the Terra Nova field in January 2002, and more production from the Ladyfern field in Western Canada. The increase in 2001 was also due to higher oil and natural gas production volumes during the year.

The effective income tax rate for exploration and production operations was lower by approximately 1.5% of pretax earnings in 2002 compared to 2001 primarily due to higher benefits in the latter year from settlement of prior-year tax matters.

Approximately 94% of the Company’s U.S. proved oil reserves and 48% of the U.S. proved natural gas reserves are undeveloped. At December 31, 2002, about 95% of the total U.S. undeveloped reserves relate to deepwater Gulf of Mexico fields, including Medusa, Front Runner and Habanero, which are currently being developed by the Company. Medusa is expected to come on stream at mid-year 2003. Habanero should start up in the third quarter 2003 and

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Front Runner is currently projected to produce first oil in 2004. On a worldwide basis, the Company has spent approximately $239 million in 2002, $208 million in 2001 and $111 million in 2000 to develop its undeveloped proved reserves. The Company expects to spend about $314 million in 2003, $142 million in 2004 and $62 million in 2005 to move undeveloped proved reserves to the developed category.

The U.S. Securities and Exchange Commission (SEC) is currently in the process of obtaining information from Murphy and other oil and gas companies operating in the Gulf of Mexico to assess how the industry is determining proved reserves related to new field discoveries. SEC regulations allow oil companies to recognize proved reserves if economic producibility is supported by either an actual production test or conclusive formation test. In the absence of a production test, compelling technical data must exist to recognize proved reserves related to the initial discovery of the oil or natural gas field. Production tests in deepwater environments are extremely expensive and the oil industry has increasingly depended on advanced technical testing to support economic producibility. Murphy has recorded proved reserves related to the initial discovery of four offshore fields based on conclusive formation tests rather than actual production tests. At the end of 2002, proved reserves for these four fields totaled 92 million barrels of oil equivalent, or approximately 20% of the Company’s worldwide proved reserves, including synthetic oil. Three of the fields are currently being developed, including the Medusa, Front Runner and Habanero fields, with expected first production for these fields ranging from mid-2003 to the first half of 2004. Murphy believes the proved reserves are properly classified. Murphy has furnished the information requested by the SEC and is unable to predict the outcome of the SEC’s staff review of the industry’s practices. This issue is not expected to have a material effect on the Company’s financial results. If the issue is not favorably resolved, the Company may be required to revise the manner in which it reports its proved reserves, which could affect its finding costs per barrel and reserve replacement ratios.

Refining and Marketing – The Company’s refining and marketing operations lost $39.9 million in 2002. Earnings from this business were a record $153.7 million in 2001, including nonrecurring gains, while earnings in 2000 totaled $54.5 million. The unfavorable result in 2002 was due to two reasons – extremely weak refining margins throughout most of the year in both the United States and United Kingdom and a $71 million gain in 2001 on sale of the Company’s former Canadian pipeline and trucking operations. Crude oil feedstock prices at the Company’s U.S. and U.K. refineries were 6% and 4% higher, respectively, in 2002 than in 2001 and the increase in wholesale and retail sales prices for refined products in 2002 did not match the increased costs of crude oil in the markets served by the Company. North American operations, which now includes refining activities in the U.S. and marketing activities in the U.S. and Canada and formerly included pipeline and trucking operations in Canada prior to the sale of this business in 2001, lost $39.2 million in 2002 compared to profits of $139.6 million in 2001 and $31.5 million in 2000. The year 2001 included the aforementioned $71 million gain on sale of pipeline and trucking operations in Canada. Excluding this gain, the 2001 results were much improved over 2000 due to stronger refining and marketing margins and a higher percentage of sales through the Company’s retail stations at Wal-Mart sites. Prior to the sale of the Canadian operations in 2001, this business generated a profit of $3.8 million in 2001 and $7.6 million in 2000. Operations in the U.K. lost $.7 million in 2002, but earned $14.1 million and $23 million in 2001 and 2000, respectively. The declines in 2002 and 2001 earnings compared to the prior year in the U.K. were caused by generally weaker refining margins than in the year before.

Unit margins (sales realizations less costs of crude oil, other feedstocks, refining operating expenses and depreciation and transportation to point of sale) averaged $.95 per barrel in North America in 2002, $3.23 in 2001 and $1.91 in 2000. North American product sales volumes increased 1% to a record 176,427 barrels per day in 2002, following a 17% increase in 2001. Sales volumes through the Company’s retail gasoline network at Wal-Mart stores continued to grow steadily throughout 2002, but lower sales volumes into the wholesale market, caused by lower finished products produced by the Company’s refineries, mostly offset this increase. Higher product sales volumes in 2001 was attributable to a combination of higher crude oil throughputs compared to the previous year at the Company’s U.S. refineries, plus continued expansion of the Company’s retail gasoline network at Wal-Mart stores.

Unit margins in the United Kingdom averaged $1.70 per barrel in 2002, $3.29 in 2001 and $4.69 in 2000. Sales of petroleum products were up 10% in 2002 to 34,204 barrels per day, while 2001 volumes were 4% higher than 2000, with both years’ increases caused by higher volumes sold in the cargo market.

Both U.S. and U.K. operations were experiencing losses during January 2003 due to unit margins being significantly weaker during this period compared to the 2002 average.

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Based on sales volumes for 2002 and deducting taxes at marginal rates, each $.42 per barrel ($.01 per gallon) fluctuation in the unit margins would have affected annual refining and marketing profits by $20.5 million. The effect of these unit margin fluctuations on consolidated net income cannot be measured because operating results of the Company’s exploration and production segments could be affected differently.

Corporate – The costs of corporate activities, which include interest income and expense and corporate overhead not allocated to operating functions, were $23.6 million in 2002, $12.8 million in 2001 and $1.7 million in 2000. The higher net cost in 2002 compared to 2001 was due to a combination of more net interest expense associated with higher borrowings and lower interest income earned. Net costs were higher in 2001 than in 2000 mainly because the earlier year included more income tax benefits and associated interest income from settlement of prior year tax matters.

Capital Expenditures

As shown in the selected financial data on page 8 of this Form 10-K report, capital expenditures, including discretionary exploration expenditures, were $868.1 million in 2002 compared to $864.4 million in 2001 and $557.9 million in 2000. These amounts included $134.8 million, $133.8 million and $111.5 million of exploration costs that were expensed. Capital expenditures for exploration and production activities totaled $631.8 million in 2002, 73% of the Company’s total capital expenditures for the year. Exploration and production capital expenditures in 2002 included $18.5 million for acquisition of undeveloped leases, $232.4 million for exploration activities, and $380.9 million for development projects. Development expenditures included $149.4 million for development of deepwater discoveries in the Gulf of Mexico; $27.4 million for the Terra Nova and Hibernia oil fields, offshore Newfoundland; $54.1 million for expansion of synthetic oil operations at the Syncrude project in Canada; and $58.9 million for heavy oil and natural gas projects in western Canada. Exploration and production capital expenditures are shown by major operating area on page F-35 of this Form 10-K report.

Refining and marketing capital expenditures totaled $234.7 million in 2002, compared to $175.2 million in 2001 and $153.8 million in 2000. These amounts represented 27%, 20% and 28% of total capital expenditures of the Company in 2002, 2001 and 2000, respectively. Refining capital spending was $150.1 million in 2002, compared to $88.9 million in 2001 and $23.5 million in 2000. The Company is in the process of expanding its Meraux, Louisiana refinery by building a hydrocracker unit to meet future clean fuel specifications and is also increasing the crude oil processing capacity of the plant from 100,000 barrels of crude oil per day to 125,000 barrels per day. This project is to be completed by the end of the third quarter of 2003. Capital expenditures related to this expansion project amounted to $116.2 million in 2002 and $55.1 million in 2001. Marketing expenditures amounted to $84.6 million in 2002, $86.3 million in 2001 and $100.9 million in 2000. The majority of marketing expenditures in each year was related to construction of retail gasoline stations at Wal-Mart sites in 21 states in the U.S. The Company began building gasoline stations at Wal-Mart stores in Canada in 2002. The Company opened 125 total stations in the U.S. and Canada in 2002, 111 in 2001 and 131 in 2000. The Company acquired the minority interest in the Manito pipeline in 2000 at a cost of approximately $27 million. The Manito pipeline as well as other Canadian pipeline and trucking assets were sold in May 2001.

Cash Flows

Cash provided by continuing operations was $527 million in 2002, $630.6 million in 2001 and $738.1 million in 2000. Nonrecurring items decreased cash flow from continuing operations by $3.4 million in 2002, $32.3 million in 2001 and $2.7 million in 2000. The reductions in cash flow from nonrecurring items in 2002 and 2001 were mainly caused by cash income taxes related to gains on sale of assets. Changes in operating working capital other than cash and cash equivalents required cash of $24.2 million in 2002 and $28 million in 2001, but provided cash of $66 million in 2000. Cash provided by operating activities was further reduced by expenditures for refinery turnarounds and abandonment of oil and gas properties totaling $15.2 million in 2002, $16.4 million in 2001 and $16.6 million in 2000.

Cash proceeds from property sales were $68.1 million in 2002, $173 million in 2001 and $20.7 million in 2000. Borrowings under notes payable and other long-term debt provided $407.6 million of cash in 2002, $88.2 million in 2001 and $175 million in 2000. Cash proceeds from stock option exercises and employee stock purchase plans amounted to $25.1 million in 2002, $18.9 million in 2001 and $3.8 million in 2000.

Property additions and dry hole costs required $834.1 million of cash in 2002, $810.2 million in 2001 and $512.3 million in 2000. Cash outlays for debt repayment during the three years included $57.8 million in 2002, $77.7 million in 2001

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and $130.5 million in 2000. The acquisition of Beau Canada in November 2000 utilized $127.5 million of cash. Cash used for dividends to stockholders was $70.9 million in 2002, $67.8 million in 2001 and $65.3 million in 2000. The Company raised its annualized dividend rate from $.75 per share to $.80 per share beginning in the third quarter of 2002.

Financial Condition

Year-end working capital totaled $136.3 million in 2002, $38.6 million in 2001 and $71.7 million in 2000. The current level of working capital does not fully reflect the Company’s liquidity position as the carrying values for inventories under last-in first-out accounting were $129 million below current cost at December 31, 2002. Cash and cash equivalents at the end of 2002 totaled $165 million compared to $82.7 million a year ago and $132.7 million at the end of 2000.

Long-term debt increased by $342 million during 2002 to $862.8 million at the end of the year, 35.1% of total capital employed, and included $74.3 million of nonrecourse debt incurred in connection with the acquisition and development of the Hibernia oil field. The increase in long-term debt in 2002 was attributable to new borrowings associated with the Company’s capital expenditure program, including deepwater Gulf of Mexico development projects, continued expansion of the Syncrude plant and an expansion project at the Company’s Meraux, Louisiana refinery. Long-term debt totaled $520.8 million at the end of 2001 compared to $524.8 million at December 31, 2000. Stockholders’ equity was $1.6 billion at the end of 2002 compared to $1.5 billion a year ago and $1.3 billion at the end of 2000. A summary of transactions in stockholders’ equity accounts is presented on page F-5 of this Form 10-K report.

Murphy had commitments of $623 million for capital projects in progress at December 31, 2002, including $82.1 million related to clean fuels and crude throughput expansion projects at the Meraux refinery; $126.3 million for costs to develop deepwater Gulf of Mexico fields, including Medusa, Front Runner and Habanero; $110.2 million for continued expansion of synthetic oil operations in Canada; and $121.8 million for future combined work commitments in Malaysia and offshore Nova Scotia. The expansion projects at the Meraux refinery include construction of a hydrocracker unit that will allow the refinery to produce low-sulfur products, an expansion of the crude oil processing capacity from 100,000 barrels per day to 125,000 barrels per day, and construction of an additional sulfur recovery complex. See further discussion regarding the Meraux projects on page 4 of this Form 10-K report.

The primary sources of the Company’s liquidity are internally generated funds, access to outside financing and working capital. The Company typically relies on internally generated funds to finance the major portion of its capital and other expenditures, but maintains lines of credit with banks and borrows as necessary to meet spending requirements. The Company anticipates that long-term debt will increase during 2003 because of significant capital expenditure commitments, as described in the preceding paragraph, and an expectation that oil and natural gas prices for much of 2003 will remain below trading ranges experienced in 2002. At December 31, 2002, the Company had access to short-term and long-term revolving credit facilities in the amount of $488 million. In addition, the Company has a shelf registration on file with the U.S. Securities and Exchange Commission that permits the offer and sale of up to $650 million in debt and equity securities. Current financing arrangements are set forth more fully in Note F to the consolidated financial statements. At February 1, 2003 the Company’s long-term debt rating by Standard and Poor’s was “A-” and by Moody’s was “Baal”. The Company’s ratio of earnings to fixed charges was 3.2 to 1 in 2002, 11.3 to 1 in 2001 and 13.4 to 1 in 2000.

Environmental

Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations. The most significant of those laws and the corresponding regulations affecting the Company’s operations are:

These acts and their associated regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. Many states also have similar statutes and regulations governing air and water, which in some cases impose additional and

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more stringent requirements. Murphy is also subject to certain acts and regulations primarily governing remediation of wastes or oil spills. The applicable acts are:

The Company is also involved in personal injury and property damage claims, allegedly caused by exposure to or by the release or disposal of materials manufactured or used in the Company’s operations.

The Company operates or has previously operated certain sites and facilities, including three refineries, 11 terminals, and approximately 80 service stations, for which known or potential obligations for environmental remediation exist. In addition the Company operates or has operated numerous oil and gas fields that may require some form of remediation; this cost is generally provided for within the Company’s liability for accrued dismantlement costs.

Under the Company’s accounting policies, an environmental liability is recorded when such an obligation is probable and the cost can be reasonably estimated. If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used. Recorded liabilities are reviewed quarterly. Actual cash expenditures often occur one or more years after a liability is recognized.

The Company’s liability for remedial obligations includes certain amounts that are based on anticipated regulatory approval for proposed remediation of former refinery waste sites. If regulatory authorities require more costly alternatives than the proposed processes, future expenditures could exceed the accrued liability by up to an estimated $3 million.

The Company has received notices from the U.S. Environmental Protection Agency (EPA) that it is currently considered a Potentially Responsible Party (PRP) at two Superfund sites. The potential total cost to all parties to perform necessary remedial work at these sites may be substantial. At one site the Company has agreed to pay $8,100 to obtain a release from further obligations. The Company’s insurance carrier has agreed to reimburse the $8,100. Based on currently available information, the Company has reason to believe that it is also a de minimus party as to ultimate responsibility at the other Superfund site. The Company has not recorded a liability for remedial costs on Superfund sites. The Company could be required to bear a pro rata share of costs attributable to nonparticipating PRPs or could be assigned additional responsibility for remediation at the one remaining site or other Superfund sites. The Company does not believe that the ultimate costs to clean-up the two Superfund sites will have a material adverse effect on its net income or cash flows in a future period.

There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on future earnings or cash flows.

Certain environmental expenditures are likely to be recovered by the Company from other sources, primarily environmental funds maintained by certain states. Since no assurance can be given that future recoveries from other sources will occur, the Company has not recorded a benefit for likely recoveries at December 31, 2002.

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The Company’s refineries also incur costs to handle and dispose of hazardous waste and other chemical substances. The types of waste and substances disposed of generally fall into the following categories: spent catalysts (usually hydrotreating catalysts); spent/used filter media; tank bottoms and API separator sludge; contaminated soils, laboratory and maintenance spent solvents; and various industrial debris. The costs of disposing of these substances are expensed as incurred and amounted to $3.3 million in 2002. In addition to these expenses, Murphy allocates a portion of its capital expenditure program to comply with environmental laws and regulations. Such capital expenditures were approximately $166 million in 2002 and are projected to be $120 million in 2003.

Other Matters

Impact of inflation – General inflation was moderate during the last three years in most countries where the Company operates; however, the Company’s revenues and capital and operating costs are influenced to a larger extent by specific price changes in the oil and gas and allied industries than by changes in general inflation. Crude oil and petroleum product prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC production levels and/or attitudes of traders concerning supply and demand in the near future. Natural gas prices are affected by supply and demand, which to a significant extent are affected by the weather and by the fact that delivery of gas is generally restricted to specific geographic areas. Because crude oil and natural gas sales prices were strong during late 2002 and early 2003, prices for oil field goods and services could be adversely affected in the future. Due to the volatility of oil and natural gas prices, it is not possible to determine what effect these prices will have on the future cost of oil field goods and services.

Accounting changes and recent accounting pronouncements – As described in Note B on page F-10 of this Form 10-K report, Murphy adopted Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138, effective January 1, 2001. In addition, the Company adopted a change in accounting for unsold crude oil production effective January 1, 2000 that resulted in an $8.7 million charge to earnings in 2000 for the cumulative effect of the accounting change.

In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 141 requires that all future business combinations be accounted for using the purchase method of accounting and that certain acquired intangible assets in a business combination be recognized and reported as assets apart from goodwill. SFAS No. 142 requires that amortization of goodwill be replaced with annual tests for impairment and that intangible assets other than goodwill be amortized over their useful lives. The Company adopted SFAS No. 141 upon its issuance and adopted SFAS No. 142 on January 1, 2002. The Company had unamortized goodwill of $51 million at December 31, 2002, which has been tested for impairment as required by SFAS No. 142 at year-end 2002. Amortization expense related to goodwill was $3.1 million for the year ended December 31, 2001.

In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which supercedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of, and the accounting and reporting provisions of APB Opinion No. 30, Reporting the Results of Operations–Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual, and Infrequently Occurring Events and Transactions. The Company adopted the provision of SFAS No. 144 effective January 1, 2002. The adoption of SFAS No. 144 had no impact on the Company. In the fourth quarter 2002, the Company sold its interest in Ship Shoal Block 113 at a gain of $10.6 million. Following the guidance of SFAS No. 144, Murphy has recorded the gain on disposal, plus the normal operating results, of Ship Shoal Block 113 as discontinued operations for all years presented.

The Company adopted Emerging Issues Task Force (EITF) Issue 02-3 in the fourth quarter 2002. This consensus requires that the results of energy trading activities be recorded on a net margin basis. Accordingly, Murphy has reflected the results of its crude oil trading activities as net revenue in its income statement, and previously reported revenues and cost of sales have been reduced by equal and offsetting amounts, with no changes to net income or cash flows. The effect of this reclassification was a net reduction of both net sales and cost of crude oil, natural gas and product purchases by approximately $269 million in 2002, $600 million in 2001 and $1.03 billion in 2000.

In July 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement

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liability must be recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed in service. When the liability is initially recorded, the Company will increase the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Upon adoption of SFAS No. 143 on January 1, 2003, the Company will recognize transition adjustments for existing asset retirement obligations, long-lived assets and accumulated depreciation, all net of related income tax effects, as the cumulative effect of a change in accounting principle. After adoption, any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability will be recognized as a gain or loss in the Company’s earnings. The Company is unable to estimate the financial statement impact as of January 1, 2003 from adoption of SFAS No. 143.

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections. SFAS No. 145 amends existing guidance on reporting gains and losses on the extinguishment of debt to prohibit the classification of the gain or loss as extraordinary, as the use of such extinguishments have become part of the risk management strategy of many companies. SFAS No. 145 also amends SFAS No. 13 to require sale-leaseback accounting for certain lease modifications that have economic effects similar to sale-leaseback transactions. The provisions of the Statement related to the rescission of Statement No. 4 is applied in fiscal years beginning after May 15, 2002. Earlier application of these provisions is encouraged. The provisions of the Statement related to Statement No. 13 were effective for transactions occurring after May 15, 2002, with early application encouraged. The adoption of SFAS No. 145 is not expected to have a material effect on the Company’s financial statements.

In June 2002, the FASB issues SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies EITF Issue 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity. The provisions of this Statement are effective for exit or disposal activities that are initiated after December 31, 2002, with early application encouraged. The adoption of SFAS No. 146 is not expected to have a material effect on the Company’s financial statements.

In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirement for Guarantees, Including Indirect Guarantees of Indebtedness to Others, an interpretation of FASB Statements No. 5, 57 and 107 and a rescission of FASB Interpretation No. 34. This Interpretation elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees issued. The Interpretation also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. The initial recognition and measurement provisions of the Interpretation are applicable to guarantees issued or modified after December 31, 2002 and are not expected to have a material effect on the Company’s financial statements. The disclosure requirements are effective for financial statements of interim and annual periods ending after December 15, 2002.

In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment of FASB Statement No. 123. This Statement amends SFAS No. 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements. Certain of the disclosure modifications are required for fiscal years ending after December 15, 2002 and are included in the notes to these consolidated financial statements.

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51. This Interpretation addresses the consolidation by business enterprises of variable interest entities as defined in the Interpretation. The Interpretation applies immediately to variable interests in variable interest entities created after January 31, 2003, and to variable interests in variable interest entities obtained after January 31, 2003. For public enterprises with a variable interest in a variable interest entity created before February 1, 2003, the Interpretation is applied no later than the beginning of the first interim reporting period beginning after June 15, 2003. The application of this Interpretation is not expected to have a material effect on the Company’s financial statements. The Interpretation requires certain disclosures in financial statements issued after January 31, 2003 if it is reasonably

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possible that the Company will consolidate or disclose information about variable interest entities when the Interpretation becomes effective.

Significant accounting policies – In preparing the Company’s financial statements in accordance with accounting principles generally accepted in the United States, management must make a number of estimates and assumptions related to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Application of certain of the Company’s accounting policies requires significant estimates. These accounting policies are described below.

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Contractual obligations and guarantees – The Company is obligated to make future cash payments under borrowing arrangements, operating leases, throughput contract, hydrogen supply agreement and capital commitments. Total payments due after 2002 under such contractual obligations are shown below.

In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide financial guarantees or letters of credit that may be drawn upon if the Company fails to perform under those contracts. The amount of commitments that expire in future periods is shown below.