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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, 2004

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  x    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.    x

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

Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on average price at June 30, 2004, as quoted by the New York Stock Exchange, was approximately $6,725,984,000.

Number of shares of Common Stock, $1.00 Par Value, outstanding at January 31, 2005 was 92,034,083.

Documents incorporated by reference:

Portions of the Registrant’s definitive Proxy Statement relating to the Annual Meeting of Stockholders on May 11, 2005 have been incorporated by reference in Part III herein.

Table of Contents

MURPHY OIL CORPORATION

TABLE OF CONTENTS – 2004 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 subdivided into geographic segments for North America and United Kingdom. Additionally, “Corporate and Other Activities” include interest income, interest expense, foreign exchange effects and overhead not allocated to the segments.

The information appearing in the 2004 Annual Report to Security Holders (2004 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 9 through 18, F-12, F-27 through F-29, F-34 through F-36, and F-38 of this Form 10-K report and on pages 6 through 14 of the 2004 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

The Company’s exploration and production business explores for and produces crude oil, natural gas and natural gas liquids worldwide.

During 2004, Murphy’s principal exploration and production activities were conducted in the United States by wholly owned Murphy Exploration & Production Company-USA (Murphy Expro USA), in Ecuador, Malaysia and the Republic of the Congo by wholly owned Murphy Exploration & Production Company-International (Murphy Expro International) 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 2004 was in the United States, Canada, the United Kingdom, Malaysia and Ecuador; its natural gas was produced and sold in the United States, Canada and the United Kingdom. MOCL owns a 5% undivided interest in Syncrude Canada Ltd. in Northern Alberta, the world’s largest producer of synthetic crude oil.

Murphy’s worldwide crude oil, condensate and natural gas liquids production from continuing operations in 2004 averaged 93,634 barrels per day, an increase of 22% compared to 2003. The increase was primarily due to a full year of production in 2004 at the Medusa and Habanero deepwater fields in the Gulf of Mexico and the West Patricia field offshore Sarawak, Malaysia. The Company’s worldwide sales volume of natural gas from continuing operations averaged 109 million cubic feet (MMCF) per day in 2004, down 2% from 2003 levels. The lower natural gas sales were due to production declines in mature producing areas that more than offset higher production from the Medusa and Habanero fields in the deepwater Gulf of Mexico.

Total crude oil, condensate and natural gas liquids production is expected to increase in 2005 because of a full year of production at the Front Runner field in the deepwater Gulf of Mexico and the Seal area in western Canada. Front Runner came on stream in December 2004. Natural gas sales volumes are expected to increase in 2005 compared to 2004 due to the higher production from the three deepwater Gulf of Mexico fields mentioned above.

In the United States, Murphy has production of oil and/or natural gas from 13 fields operated by the Company and 15 fields operated by others. Of the total producing fields at December 31, 2004, four are in the deepwater Gulf of Mexico, 20 are in more shallow waters on the Gulf of Mexico continental shelf, three are onshore in Louisiana and one is the Northstar field in Alaska. The Company’s primary focus in the U.S. is in the deepwater Gulf of Mexico, which is generally defined as water depths of 1,000 feet or more. The Company operates and owns a 60% interest in the Medusa field, in Mississippi Canyon Blocks 538/582. Medusa produced about 12,000 barrels of oil per day and 12 MMCF of gas

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per day net to the Company in 2004. Peak net production from Medusa is expected to be 25,000 barrels of oil equivalent per day. The Company owns a 33.75% interest in the Habanero field in Garden Banks Block 341. Habanero, which is operated by Shell, produced about 4,000 barrels of oil per day and 10 MMCF of gas per day net to the Company in 2004. The Front Runner field in Green Canyon Blocks 338/339 came on stream in December 2004 and will have additional wells completed and hooked up throughout 2005. Murphy owns 37.5% and operates the Front Runner field, which is expected to have peak net production of 20,000 barrels of oil equivalent per day in 2006. Hurricane Ivan caused temporary shut in of wells and damaged certain facilities which ultimately reduced the Company’s annualized production in the U.S. during 2004 by about 4,000 barrels of oil equivalent per day. The other deepwater producing field is at Tahoe in Viosca Knoll Block 783 (30%). Tahoe is operated by Shell and in 2004 produced about 13 MMCF of natural gas per day and 300 barrels of oil per day net to the Company. In 2004, Murphy announced a discovery at the Thunderhawk wildcat well in Mississippi Canyon Block 734 and in early 2005 announced a discovery at South Dachshund in Lloyd Ridge Blocks 1 and 2. Murphy holds an interest in 183 blocks in the deepwater Gulf of Mexico, and expects to drill about four deepwater prospects per year over the next several years. The Company’s largest producing field on the continental shelf of the Gulf of Mexico is at South Timbalier Blocks 63/86 (100%/96%). Murphy operates South Timbalier Blocks 63/86 with a combined net production of about 400 barrels of oil per day and 10 MMCF per day in 2004. Onshore production, which is mostly natural gas, is primarily located on several leases in Vermilion Parish, Louisiana. Murphy’s net production in 2004 from onshore fields was 26 MMCF per day. The Company owns approximately a 1.4% working interest in the Northstar field operated by BP in Alaska. Total net oil production for this field was approximately 800 barrels per day in 2004.

In Canada, the Company owns an interest in three legacy assets, the Hibernia and Terra Nova fields offshore Newfoundland and Syncrude Canada Ltd. In addition, the Company owned interests in two heavy oil areas and one natural gas area in the Western Canada Sedimentary Basin (WCSB) at the end of 2004. In the second quarter 2004, the Company completed the sale of most of its WCSB assets, while retaining a limited number of heavy oil and natural gas fields which are strategic to the Company. Assets sold produced about 20,000 barrels of oil equivalent per day in 2003 and had total proved reserves of approximately 43 million barrels of oil equivalent at the time of sale. In late 2004, Murphy acquired additional acreage in the Seal heavy oil area at a cost of $121 million. Murphy holds a 6.5% interest in Hibernia and a 12% interest in Terra Nova, with these being the first two fields on production in the Jeanne d’Arc Basin, offshore Newfoundland. Total net production in 2004 was 12,700 barrels of oil per day from Hibernia, which is operated by Hibernia Management and Development Company, while net production from Terra Nova, which is operated by PetroCanada, was also 12,700 barrels of oil per day. Murphy owns a 5% undivided interest in Syncrude Canada Ltd., a joint venture located about 25 miles north of Fort McMurray, Alberta. Syncrude utilizes its assets to extract bitumen from oil sand deposits and to upgrade this bitumen into a high-value synthetic crude oil. Syncrude is currently expanding its facilities and is adding a third coker that will allow for increased production beginning in 2006. Total net production in 2004 was 11,800 barrels of crude oil per day, but with the expansion net production is expected to exceed 15,000 barrels per day in 2006. Although Syncrude produces a very high quality synthetic crude oil from bitumen, the U.S. Securities and Exchange Commission (SEC) does not allow the Company to include Syncrude’s reserves in its proved oil reserves, which are reported on page F-32. The SEC considers Syncrude to be a mining operation, and not a conventional oil operation.

Murphy produces oil and natural gas in the United Kingdom sector of the North Sea. The Company’s primary oil production in the U.K. is now derived from two areas, Schiehallion and Mungo/Monan. Murphy owns 5.88% of the Schiehallion field operated by BP. This field is located in an area known as the Atlantic Margin and lies west of the Shetland Islands. Schiehallion produces oil into a Floating Production Storage and Offloading vessel (FPSO). The oil is transported via dedicated tanker to Sullom Voe terminal, where the oil is sold to third parties. Schiehallion produced approximately 5,300 net barrels of oil per day in 2004. Schiehallion development will continue with further infield drilling planned in 2005 onwards. Murphy owns a 4.843% interest in the FPSO, which also handles production from a nearby field owned by others. Mungo/Monan is also operated by BP and is 12.65% owned by Murphy. The Mungo field produces through an unmanned platform, while Monan is produced through subsea facilities. Both the platform and subsea facilities are tied to a central processing facility that is linked to the Forties pipeline system. In 2004, the Mungo and Monan fields produced approximately 4,500 barrels of oil per day, net to Murphy’s interest. In 2004, the Company sold its interest in the “T” Block field. Production from this field averaged about 1,600 net barrels per day in 2004 prior to the sale.

In Ecuador, Murphy owns a 20% working interest in Block 16, which is operated by Repsol YPF under a participation contract. The Company’s net production was about 7,700 barrels of oil per day in 2004. Between June and December 2004, Murphy did not receive its equity share of oil sales from Block 16 due to a dispute with the operator involving the Company’s new transportation and marketing arrangements. Murphy is owed more than 1.5 million barrels from other Block 16 working interest owners as of December 31, 2004. Murphy expects to make up this shortfall owed by the other owners in 2005 by either a cash settlement or an allocation of additional 2005 production barrels to the Company.

The Company has majority interests in eight separate production sharing contracts (PSCs) in Malaysia. The Company serves as the operator of all these areas, which cover approximately 14.4 million acres in total. Murphy has an 85% interest in two shallow water blocks, known as SK 309 and SK 311. The West Patricia field in Block SK 309, discovered in 2002, came on stream in May 2003. The Company’s net share of production averaged about 11,900 barrels of oil per day in 2004. The Company made a major discovery at the Kikeh field in deepwater Block K in 2002 and added a discovery at Kikeh Kecil in 2003 and discoveries at Kakap, Senangin and Kikeh deep formation in 2004. Further exploration and appraisal drilling will occur in the 80% owned Block K in 2005. In 2004, our Board of Directors and Malaysian authorities sanctioned the Kikeh field development plan, and in early 2005 engineering and construction contracts for major equipment were awarded. The Company added proved oil reserves of 40.5 million barrels related to the Kikeh field in Block K Malaysia at year-end 2004. These proved reserves did not include any volumes attributable to pressure maintenance programs that the Company intends to utilize to produce the Kikeh field when

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production begins, which is currently projected to be in the second half of 2007. Murphy also owns 75% interests in Blocks PM 311 and PM 312, located offshore peninsular Malaysia. Murphy announced discoveries at Kenarong and Pertang in PM 311 in 2004. The Company has a number of exploration prospects in Block H (80%) in deepwater. The Company was awarded interests in PSCs covering deepwater Blocks L (60%) and M (70%) in early 2003. The Sultanate of Brunei also claims this acreage. Murphy drilled a wildcat well in Block L in mid-2003. Well results have been kept confidential and well costs of $12 million are held in suspension pending the resolution of the ownership issue. The Company is unable to predict when the ownership issue will be resolved or the outcome of such a resolution. A total of 2.9 million gross acres associated with Blocks L and M have been included in the acreage table below.

The Company finalized the award of Production Sharing Agreements (PSAs) covering two offshore blocks in the Republic of the Congo in 2004. The Company has an 85% interest in each PSA. These blocks are named Mer Profonde Sud and Mer Profonde Nord, and together, these blocks cover approximately 1.8 million acres with water depths ranging from 490 to 6,900 feet. Murphy drilled its first exploration well in late 2004 and in early 2005 announced a significant oil discovery at Azurite Marine #1 in Mer Profonde Sud.

Murphy’s estimated net quantities of proved oil and gas reserves and proved developed oil and gas reserves at December 31, 2001, 2002, 2003 and 2004 by geographic area are reported on pages F-31 and F-32 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.

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, 2004 are shown on page 8 of the 2004 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-30 through F-38 of this Form 10-K report.

At December 31, 2004, 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 attributable to Murphy’s working interest.

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The only significant undeveloped acreage that expires in the next three years is approximately 9.5 million net acres in Malaysia and .9 million acres offshore the East Coast of Canada. The Company is currently negotiating to extend the exploration rights for the Malaysian 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.

The following table shows the number of oil and gas wells producing or capable of producing at December 31, 2004.

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

The increase in the number of development dry hole wells in Canada in 2004 was caused by 23 nonproducing stratigraphic wells drilled in the Seal area for the purpose of placement of horizontal development wells for the field.

Murphy’s drilling wells in progress at December 31, 2004 are shown below.

Additional information about current exploration and production activities is reported on pages 5 through 10 of the 2004 Annual Report.

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Refining and Marketing

The Company’s refining and marketing businesses are located in North America and the United Kingdom, and primarily consist of operations that refine crude oil and other feedstocks into petroleum products such as gasoline and distillates, buy and sell crude oil and refined products, and transport and market petroleum products.

Murphy Oil USA, Inc. (MOUSA), a wholly owned subsidiary of Murphy Oil Corporation, 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 per day. Refinery capacities at December 31, 2004 are shown in the following table.

Murphy has expanded the Meraux refinery allowing the refinery to now meet new low-sulfur gasoline specifications which become effective for the Company in 2008. The expansion included a new hydrocracker unit, central control room and two new utility boilers; expansion of the crude oil processing capacity to 125,000 barrels per stream day (b/sd); expansion of naphtha hydrotreating capacity to 35,000 b/sd; expansion of the catalytic reforming capacity to 32,000 b/sd; and construction of a new sulfur recovery complex, including amine regeneration, sour water stripping and high efficiency sulfur recovery. The Meraux plant had no solvent deasphalting processing capability during 2004 because of the fire in June 2003 that destroyed the Residual Oil Supercritical Extractor (ROSE) unit. The ROSE unit has been rebuilt, primarily using proceeds of property insurance, and was restarted in early 2005. While the ROSE unit was being rebuilt, the refinery produced a larger volume of heavy fuel oil. During 2004 the Company also completed an FCC gasoline hydrotreater unit at its Superior, Wisconsin refinery, that allows the refinery to meet low-sulfur gasoline specifications.

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, one terminal that is jointly owned and operated by others, and numerous terminals owned by others. Of the wholly owned terminals, three are supplied by marine transportation, three are supplied by truck, three are supplied by pipeline and two are adjacent to MOUSA’s refineries. MOUSA receives products at the terminals owned by others either in exchange for deliveries from the Company’s terminals or by outright purchase. The Company sold all but one of its jointly owned terminals in early 2004. At December 31, 2004, the Company marketed products through 752 Murphy USA stations and 366 branded wholesale SPUR stations. MOUSA plans to add about 150 new Murphy USA stations at Wal-Mart sites in the southern and midwestern United States in 2005. The Company’s Canadian subsidiary operates eight Murphy Canada^TM stations at Wal-Mart sites in Canada.

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 the master agreement is entered into, which contains the terms specific to

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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 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 38.6% of total Company revenues in 2004, 35.8% in 2003 and 30.3% in 2002. 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.

At the end of 2004, 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 358 branded stations primarily under the brand name MURCO.

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.

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, 2004 are reported on pages 11 through 14 of the 2004 Annual Report.

Employees

At December 31, 2004, Murphy had 5,826 employees – 2,139 full-time and 3,687 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 2004, the Company’s production of oil and natural gas represented approximately .1% of the respective worldwide totals. Murphy owned approximately 1% of the crude oil refining capacity in the United States and its market share of U.S. retail gasoline sales was approximately 1.4%.

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.

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 18 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 changes caused by governmental and political considerations and are often made 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

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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, 2004, the Company maintained total excess liability insurance with limits of $750 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, 2005, 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 50; President and Chief Executive Officer since October 1994 and Director and Member of the Executive Committee since 1993.

Steven A. Cossé – Age 57; Executive Vice President since February 2005 and General Counsel since August 1991. Mr. Cossé was elected Senior Vice President in 1994 and Vice President in 1993.

W. Michael Hulse – Age 51; Executive Vice President – Worldwide Downstream Operations effective April 2003. Mr. Hulse has been President of MOUSA from November 2001 to present. He served as President of Murphy Eastern Oil Company from April 1996 to November 2001.

Bill H. Stobaugh – Age 53; Senior Vice President since February 2005. Mr. Stobaugh joined the Company as Vice President in 1995.

Kevin G. Fitzgerald – Age 49; Treasurer since July 2001. Mr. Fitzgerald was Director of Investor Relations from 1996 to June 2001.

John W. Eckart – Age 46; Controller since March 2000.

Walter K. Compton – Age 42; Secretary since December 1996.

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$3.61 billion. In September 2004 the court summarily dismissed all claims against MOCL’s president and all but C$356 million of the counterclaim against the Company; however, this dismissal order is currently on appeal. It is anticipated that a trial concerning the 25% disputed interest and any remaining issues will commence in 2005. While the litigation is in the discovery stage 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 net income, financial condition or liquidity in a future period. In the unlikely event that Predator were to prevail in its counterclaim in an amount approaching the damages sought, Murphy would incur a material expense in its consolidated statement of income, and would have a material effect on its financial condition and liquidity.

On June 10, 2003, a fire severely damaged the Residual Oil Supercritical Extraction (ROSE) unit at the Company’s Meraux, Louisiana refinery. The ROSE unit recovers feedstock from the heavy fuel oil stream for conversion into gasoline and diesel. Subsequent to the fire, numerous class action lawsuits have been filed seeking damages for area residents. All the lawsuits have been administratively consolidated into a single legal action in St. Bernard Parish, Louisiana, except for one such action which was filed in federal court. Additionally, individual residents of Orleans Parish, Louisiana, have filed an action in that venue. On May 5, 2004, plaintiffs in the consolidated action in St. Bernard Parish amended their petition to include a direct action against certain of the Company’s liability insurers. In responding to this direct action, one of the Company’s insurers, AEGIS, has raised lack of coverage as a defense. The Company believes that this contention lacks merit and has been advised by counsel that the applicable policy does provide coverage for the underlying incident. Because the Company believes that insurance coverage exists for this matter, it does not expect to incur any significant costs associated with the class action lawsuits. Accordingly, the Company continues to believe that the ultimate resolution of the June 2003 ROSE fire litigation will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

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On March 5, 2002, two of the Company’s subsidiaries filed suit against Enron Canada Corp. (Enron) to collect approximately $2.1 million owed to Murphy under canceled gas sales contracts. On May 1, 2002, Enron counterclaimed for approximately $19.8 million allegedly owed by Murphy under those same agreements. Although the lawsuit in the Court of Queen’s Bench, Alberta, is in its early stages and no assurance can be given about the outcome, the Company does not believe that the Enron counterclaim is meritorious and does not believe that the ultimate resolution of this matter will have a material adverse effect on its net income, financial condition or liquidity in a future period. In the unlikely event that Enron were to prevail in the lawsuit, the Company could incur expense in a future period approximating the amount of the judgment.

Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of matters referred to in this item is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity 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 2004.

PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The Company’s Common Stock is traded on the New York Stock Exchange using “MUR” as the trading symbol. There were 2,864 stockholders of record as of December 31, 2004. Information as to high and low market prices per share and dividends per share by quarter for 2004 and 2003 are reported on page F-38 of this Form 10-K report.

Item 6. SELECTED FINANCIAL DATA

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

Overview

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. A more detailed description of the Company’s significant assets can be found in Items 1 and 2 of this Form 10-K report.

Murphy generates revenue primarily by selling its oil and natural gas production and its refined petroleum products to customers at hundreds of locations in the United States, Canada, the United Kingdom and other countries. The Company’s revenue is highly affected by the prices of oil, natural gas and refined petroleum products it sells. Also, because crude oil is purchased by the Company for refinery feedstocks, natural gas is purchased for fuel at its refineries and oil fields, and gasoline is purchased to supply its retail gasoline stations in North America that are primarily located at Wal-Mart stores, the purchase prices for these commodities also have a significant effect on the Company’s costs. In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products, amortization of capital expenditures and expenses related to exploration. Profits and generation of cash in the Company’s downstream operations are dependent upon achieving an adequate margin, which is determined by the sales prices for refined petroleum products less the costs of refinery feedstocks and gasoline purchases and expenses associated with manufacturing, transporting and marketing these products. Murphy also incurs certain costs for general company administration and for capital borrowed from lending institutions.

In general, worldwide oil prices and North American natural gas prices were stronger in 2004 than in 2003. The average price for a barrel of West Texas Intermediate crude oil in 2004 was $41.47, an increase of 34% compared to 2003. The NYMEX natural gas price averaged $6.18 per million British Thermal Units (MMBTU) in 2004, up 13% over 2003. These price improvements were a significant factor leading to higher profits in the Company’s exploration and production business in 2004 compared to the prior year. If the prices for crude oil and natural gas decline significantly in 2005 or beyond, the Company would expect this to have an unfavorable impact on operating profits for its exploration and production business. Such lower oil and gas prices could, but may not, have a favorable impact on the Company’s refining and marketing operating profits.

Results of Operations

The Company had net income in 2004 of $701.3 million, $7.51 per diluted share, compared to net income in 2003 of $294.2 million, $3.17 per diluted share. In 2002 the Company earned $111.5 million, $1.21 per diluted share. The higher net income in 2004 compared to 2003 was caused by a combination of better earnings in the Company’s exploration and production and refining and marketing operations, partially offset by higher net costs for corporate functions. The income improvement in 2003 compared to 2002 was due to higher earnings in the exploration and production business, a smaller loss in the refining and marketing area, and lower net costs for corporate functions. Further explanations of each of these variances are found in the following sections.

Each of the three years ended December 31, 2004 included income from discontinued operations. In the second quarter 2004 the Company sold most of its conventional oil and natural gas properties in Western Canada for cash proceeds of $583 million. This sale generated an after-tax gain of $171.1 million. In December 2002 the Company sold its interest in Ship Shoal Block 113 in the Gulf of Mexico, with a resulting 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, the gains on disposal of these assets and operating results for the fields prior to their sale have been included, net of income tax expense, as Discontinued Operations in the consolidated statements of income for the three-year period ended December 31, 2004. Income from discontinued operations was $204.9 million, $2.20 per share, in 2004, $22.8 million, $.25 per share, in 2003, and $24.2 million, $.26 per share, in 2002.

On January 1, 2003, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. Upon adoption of SFAS No. 143, the Company recorded an expense of $7 million, net of $1.4 million in income taxes, as the cumulative effect of a change in accounting principle. Further explanation of this accounting change is included in Note G to the consolidated financial statements. Income before the cumulative effect of a change in accounting principle was $301.2 million, $3.25 per share, in 2003.

Income from continuing operations was $496.4 million, $5.31 per share, in 2004, $278.4 million, $3.00 per share, in 2003, and $87.3 million, $.95 per share, in 2002.

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2004 vs. 2003 – Net income in 2004 was $701.3 million, $7.51 per share, compared to $294.2 million, $3.17 per share, in 2003. Both periods included income from discontinued operations associated with conventional oil and natural gas properties in Western Canada that were sold in the second quarter 2004. Income from discontinued operations amounted to $204.9 million in 2004 and $22.8 million in 2003, $2.20 and $.25 per share, respectively. The 2004 amount included a $171.1 million gain net of taxes associated with the sale, which netted proceeds of $583 million for the Company. All financial information has been reclassified to present the operating results for these properties as discontinued operations. The 2003 period included an after-tax expense of $7 million, $.08 per share, for a cumulative effect of a change in accounting principle associated with adoption of SFAS No. 143, Accounting for Asset Retirement Obligations. Income from continuing operations totaled $496.4 million, $5.31 per share, in 2004 compared to $278.4 million, $3.00 per share, in 2003. The $218 million improvement in income from continuing operations in 2004 was due to a combination of higher earnings from the Company’s exploration and production and refining and marketing operating businesses. Higher net costs of corporate activities partially offset the better results from these operating businesses. Exploration and production (E&P) operating results improved $208.9 million mostly due to higher oil and natural gas sales prices, higher oil sales volumes, and a $31.9 million deferred income tax benefit in Malaysia due to the expectation that temporary differences associated with exploration and other costs incurred to-date in Block K will be utilized to reduce future taxable income. The E&P results were unfavorably affected in 2004 by higher exploration expenses and lower natural gas sales volumes compared to 2003. Refining and marketing (R&M) operating results improved by $93.1 million in 2004 compared to 2003 primarily due to much stronger realized margins on petroleum products sold by the U.S. and U.K. businesses. The net costs of corporate activities were $84 million higher in 2004 because of a 5% withholding tax on a $550 million dividend to Murphy Oil Corporation from the Company’s Canadian subsidiary, unfavorable foreign exchange variances, a $20.1 million tax benefit in 2003 related to settlement of U.S. tax matters, lower capitalized interest costs due to the completion of significant E&P development projects, and higher administrative expenses related mostly to Sarbanes-Oxley compliance and retirement plans. The Canadian withholding tax in 2004 amounted to $27.5 million of costs. Foreign exchange losses were $18.6 million after tax in 2004 compared to a benefit of $5.4 million in 2003. These 2004 losses were primarily associated with U.S. dollar balances of cash and other net assets held by the Company’s Canadian and U.K. subsidiaries, which generally use local currency as their functional currency for bookkeeping purposes.

Sales and other operating revenues in 2004 increased $3.2 billion compared to 2003 mostly due to higher prices for oil, natural gas and petroleum products sold, higher sales volumes of crude oil and petroleum products, and higher merchandise sales revenue at retail gasoline stations. Gain on sale of assets increased by $8.1 million in 2004 due to a higher profit on sales of E&P properties in the year compared to 2003. Interest and other income was unfavorable by $17.5 million in 2004 versus 2003 mostly because of pretax foreign exchange losses of $26.6 million in 2004 compared to gains of $5.6 million in 2003; the foreign exchange effects were partially offset by higher interest income earned on invested cash balances during 2004. Crude oil and product purchases expense increased by $2.5 billion in 2004 due to the higher prices for crude oil purchased as refinery feedstocks and petroleum products purchased for sale at retail gasoline stations, and higher purchased volumes of crude oil, petroleum products and merchandise for resale compared to 2003. Operating expenses increased $157.3 million in 2004 with the change due to higher lifting costs caused by crude oil production growth and higher unit rates, higher refining and gasoline station expenses, and higher insurance and repair costs caused mostly by storms in the Gulf of Mexico. Exploration expenses rose by $51.6 million in 2004 mostly due to higher dry hole costs offshore Eastern Canada and in Malaysia. Selling and general expenses were $12.8 million higher in the current year and increased due to consulting fees associated with Sarbanes-Oxley compliance, plus increases for salaries, retirement and other benefits, and incentive compensation. Depreciation, depletion and amortization rose by $62.6 million mostly due to higher production of crude oil and higher depreciation of refining and marketing assets. Property impairments of $8.3 million in 2003 related to write-down of a refined products terminal closed by the company, write-off of certain property costs that were rendered obsolete at the Meraux refinery and the write-down of a natural gas field in the Gulf of Mexico due to downward revisions in reserves caused by poor well performance. Accretion of asset retirement obligations increased by $.3 million, mostly due to drilling wells and facilities added during 2004. Interest expense was $1.5 million less than in 2003 mostly due to lower average debt outstanding during 2004. Capitalized interest credited to income and included in capital expenditures decreased by $15.1 million due to completion of the Medusa development project in the Gulf of Mexico and the expansion project at the Meraux refinery. Income tax expense was $212.7 million higher in 2004 than 2003 mostly due to higher pretax income, but also because of a $20.1 million benefit in 2003 from settlement of prior year U.S. tax audits.

2003 vs. 2002 – Net income in 2003 was $294.2 million, $3.17 per diluted share, compared to $111.5 million, $1.21 per diluted share, in 2002. The 2003 period included an after-tax expense of $7 million, $.08 per share, related to a cumulative effect of a change in accounting principle associated with adoption of SFAS No. 143, Accounting for Asset Retirement Obligations. The 2003 period included profit on discontinued operations of $22.8 million, $.25 per share, while the 2002 period included $24.2 million, $.26 per share. Excluding the accounting change in 2003 and the results of discontinued operations in both years, income from continuing operations was $278.4 million, $3.00 per share, in 2003, and $87.3 million, $.95 per share, in 2002. The $191.1 million higher income from continuing operations in 2003 compared to 2002 was attributable to $152.6 million higher earnings from exploration and production operations, a $28.7 million lower loss from refining and marketing operations, and $9.8 million of lower net costs from corporate activities. Earnings from exploration and production operations were up in 2003 primarily due to higher oil and natural gas sales prices, a $34 million after-tax gain on sale of the Ninian and Columba fields in the U.K. North Sea, higher oil and natural gas production, higher tax benefits from settlement and rate adjustments, and lower property impairment and exploration expenses. Refining and marketing results in both North America and the United Kingdom showed significant improvements in 2003. Most of the improvement in North America was generated by stronger margins in the retail marketing portion of the business. Higher margins in the U.K. led to better income from this area. The net costs of corporate activities were lower in 2003 primarily due to higher corporate income tax benefits related to settlement of prior year tax matters and lower net interest costs, partially offset by higher selling and general expenses.

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Sales and other operating revenues in 2003 increased by $1.3 billion compared to 2002 due to higher sales volumes for crude oil, natural gas and refined petroleum products, higher sales prices for oil, natural gas and refined products, and higher merchandise sales at retail gasoline stations. Gain on sale of assets was $52.4 million higher in 2003 primarily due to a $50 million pretax profit on sale of the Ninian and Columba fields in the U.K. North Sea. Crude oil and product purchases expense increased by $975.5 million in 2003 due to higher costs of crude oil used for refinery feedstock, and higher costs and volumes of gasoline and merchandise purchased for sale at the Company’s retail gasoline stations. Operating expenses increased by $82.4 million in 2003 due to higher operating and repair costs at refineries and higher operating costs at the Company’s growing retail gasoline station chain. Selling and general expenses rose by $27.1 million in 2003 primarily due to higher retirement and incentive compensation expenses and higher costs for Malaysian operations. Exploration expenses were $11.3 million lower in 2003 mostly due to less exploratory costs incurred in Malaysia. Depreciation, depletion and amortization expense increased by $61.3 million in 2003 due to new production from the West Patricia field, offshore Sarawak Malaysia, and higher depreciation associated with the Company’s growing retail gasoline station chain. Impairment of long-lived assets was $23.3 million lower in 2003 as the prior year included costs related to write-off of Destin Dome Blocks 56 and 57, offshore Florida. The 2003 statement of income included $9.7 million for accretion on discounted abandonment liabilities following the adoption of SFAS No. 143 on January 1, 2003. Because the abandonment liabilities are carried on the balance sheet at a discounted fair value, accretion must be recorded annually so that the liability will be recorded at full value at the time the abandonment occurs. Interest expense rose by $6.2 million in 2003 due to higher average borrowings under long-term debt during the year. The portion of interest capitalized increased by $12.7 million due to higher capital expenditures for development of deepwater Gulf of Mexico fields and expansion projects at Syncrude and the Meraux refinery. Income tax expense was $61.5 million more in 2003 mostly caused by higher pretax earnings, the effects of which were partially offset by a $20.1 million benefit from settlement of prior year tax audits in the U.S., a $10.1 million benefit related to enacted tax rate reductions in Canada, and an $11.4 million credit from recognition of deferred tax benefits in Malaysia.

In the following table, the Company’s results of operations for the three years ended December 31, 2004 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.

Exploration and Production – Earnings from exploration and production operations were $512.3 million in 2004, $303.4 million in 2003 and $150.8 million in 2002. The increase in 2004 earnings compared to 2003 was due to a 37% higher average realized oil sales price, a 24% higher realized sales price for North American natural gas, a 17% higher sales volume of crude oil, condensate and natural gas liquids, a $31.9 million deferred income tax benefit on inception-to-date Block K exploration and other expenses, and lower impairment charges. These favorable variances more than offset lower volumes of natural gas production, higher extraction costs associated with increased oil production, higher exploration expenses caused by more dry hole costs offshore Eastern Canada and in Malaysia, higher insurance costs related to a retrospective premium adjustment on property insurance coverage and higher costs to repair damages to facilities caused by Hurricane Ivan. Higher oil production was attributable to a full year of production at Medusa and Habanero in the deepwater Gulf of Mexico and at West Patricia in Block SK 309 in Malaysia. The decline in natural gas production was due to field decline at Amethyst in the U.K. North Sea and downtime in the Gulf of Mexico for repairs for Hurricane Ivan.

The improvement in earnings in 2003 compared to 2002 was primarily caused by a 8% higher realized worldwide oil sales price, a 57% higher realized natural gas sales price in North America, record crude oil production that was 13% higher than in 2002, a 4% increase in natural gas sales volumes, a $34 million after-tax gain on sale of the Ninian and Columba fields in the U.K. North Sea, higher tax benefits from settlements

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and rate adjustments, and lower expenses related to property impairments and exploration. Higher oil production was mostly attributable to start up in May 2003 of the West Patricia field, offshore Sarawak Malaysia. The reduction in property impairment expense in 2003 was primarily related to the write-off of the remaining costs for Destin Dome Blocks 56 and 57, offshore Florida, in 2002. The decline in exploration expenses was mostly attributable to lower exploratory costs in Malaysia.

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-34 and F-35 of this Form 10-K report. Daily production and sales rates and weighted average sales prices are shown on page 8 of the 2004 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 93,634 barrels per day in 2004, 76,620 barrels per day in 2003 and 67,549 barrels in 2002. Oil production in 2004 was a new annual record for Murphy Oil. The 22% increase in worldwide oil production was primarily attributable to production growth in the U.S. and Malaysia. Oil production in Canada and the U.K. declined in 2004 compared to 2003. U.S. oil production increased more than 300% to 19,314 barrels per day due to a full year of production in 2004 from the Medusa and Habanero fields. Both these fields came on stream in November 2003. Heavy oil production in Canada increased 24% to 5,838 barrels per day due to a heavy oil drilling program in the Seal area during 2004, plus additional producing acreage acquired in this area during the fourth quarter of 2004. Production at the Hibernia field off the East Coast of Canada was essentially flat with 2003 at 12,736 barrels per day, but the Terra Nova field saw production decrease 19% to 12,671 barrels per day, with the decline mostly due to mechanical problems and an oil spill that occurred during the year. Net synthetic oil production from the Syncrude project was 11,794 barrels per day, a 13% increase from 2003. The increase at Syncrude was in line with higher gross production, which was caused by better operational efficiency and less downtime in 2004 compared to 2003. Oil production in the U.K. was lower by 25% and averaged 11,011 barrels per day. The Company sold its interest in the “T” Block field in 2004 and the Ninian and Columba fields in 2003. Also, production from the Schiehallion and Mungo/Monan fields was down in 2004 due to normal decline. Production in Ecuador rose almost 50% in 2004 due to a full year of operation of the new heavy oil pipeline. In prior years, production restrictions were in effect due to limitations caused by inadequate pipeline capacity between the primary oil producing region in the country’s interior to the coast where sales occur. In spite of the higher Ecuadorian production in 2004, total sales volumes in this country in 2004 were lower than 2003 because no sales occurred from Block 16 during the second half of the year due to a dispute with the operator of the field over Murphy’s new transportation and marketing arrangements. Murphy expects to make up this sales volume shortfall of over 1.5 million barrels in 2005. Malaysian oil production rose 63% in 2004 and averaged 11,885 barrels per day, caused by a full year of production in the current year from the West Patricia field in Block SK 309 versus a partial year in 2003.

Comparing 2003 to 2002, oil production in the United States increased 10% to 4,526 barrels per day. Production from two new deepwater Gulf of Mexico fields – Medusa and Habanero – that came on stream in November 2003 more than offset production declines from mature fields. Oil production in Canada increased 11% in 2003 to 44,935 barrels per day. The 2003 production increase was primarily related to higher volumes produced offshore Newfoundland at the Terra Nova and Hibernia fields. Production at Terra Nova increased 26% and averaged 15,712 barrels per day in 2003. Hibernia production increased by 11% to 12,822 barrels per day in 2003. Net production from the synthetic oil operation known as Syncrude fell 879 barrels per day, or 8%, in 2003 due to less efficient operations caused by more downtime for repairs. Production of light oil decreased 674 barrels per day, or 54%, due to continued field decline and various property sales during the year. Heavy oil production in Canada increased 1,096 barrels per day, or 30%, during 2003 due to the results of development drilling, which was partially offset by lower production from various properties sold during the year. U.K. production was down by 3,616 barrels per day, or 20%, primarily due to sale of the Ninian and Columba fields in mid-2003 and production decline at the Mungo/Monan field. The Company produced 5,172 barrels of oil per day in

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Ecuador, 14% higher than in 2002, primarily due to a new heavy oil pipeline that began operations in the last half of 2003. Production began at the Company’s West Patricia field in Block SK 309, offshore Sarawak Malaysia, in May 2003. Net production from West Patricia averaged 7,301 barrels per day for all 2003, but averaged over 11,000 barrels per day since start-up.

Worldwide sales of natural gas from continuing operations were 109.5 million cubic feet per day in 2004, 111.8 million in 2003 and 107.7 million in 2002. Sales of natural gas in the United States were 88.6 million cubic feet per day in 2004, 82.3 million in 2003 and 88.1 million in 2002. Sales in the U.S. increased in 2004 as higher volumes produced during the full production year at the Medusa and Habanero fields in the deepwater Gulf of Mexico more than offset declines at other more mature fields. Sales volumes were unfavorably affected by Hurricane Ivan which temporarily shut in most production in the Central Gulf of Mexico and severely damaged certain facilities, such as at the Tahoe field in Viosca Knoll Block 783, which was off production for the entire fourth quarter following the storm. The reduction in 2003 U.S. sales volumes was due to lower deliverability from mature fields in the Gulf of Mexico. Natural gas sales from continuing operations in Canada fell from 19.9 million cubic feet per day in 2003 to 14 million in 2004, a reduction of 30%. The decrease was mostly caused by normal production decline at the Rimbey gas field. Canadian natural gas sales had increased in 2003 due to higher production volumes at Rimbey. Natural gas sales in the United Kingdom were down from 9.6 million cubic feet per day in 2003, to 6.9 million cubic feet in 2004. The 28% decrease in 2004 was due to normal declines at the Amethyst field in the U.K. North Sea. Natural gas sales volumes were up 37% in 2003 compared to 2002 due primarily to higher sales nominations at the Amethyst.

Worldwide crude oil sales prices have risen in each of the last two years. Oil prices rose in 2004 due to a strong world economy, real and perceived instability in worldwide crude oil production levels, and effective production output controls by OPEC producers. Murphy realized on average crude oil and condensate sales price of $35.92 per barrel in 2004, a 37% increase over the 2003 realized average price of $26.15. The worldwide average price was reduced $2.00 per barrel by the effects of the Company’s 2003 hedging program. The Company had hedged the sales price in 2003 for most of its heavy oil production in Canada and light oil production in the U.S., as well as a portion of its offshore and synthetic crude production in Canada. The average sales price in the U.S. was $35.35 per barrel in 2004, up 46%. Canadian heavy oil prices increased 64% in 2004, and averaged $20.26 per barrel. The Company’s selling price for Canadian offshore production from the Hibernia and Terra Nova fields averaged $36.60 per barrel in 2004, up 35% versus 2003. Synthetic oil production at Syncrude averaged $40.35 per barrel in 2004, 62% higher than in 2003. Murphy’s UK North Sea oil production averaged selling for $36.82 per barrel in the current year, 24% higher than 2003. Oil production sold for $24.78 per barrel in Ecuador and $41.35 per barrel in Malaysia, increases of 8% and 41%, respectively. No sales occurred from Block 16 in Ecuador during the second half of 2004 due to a dispute with the field’s operator over Murphy’s new transportation and marketing arrangements. Because of the lack of sales, the Company’s Ecuador operations did not benefit from higher average oil prices during the last six months of the just completed year. Murphy expects to make up this sales volume shortfall of over 1.5 million barrels in 2005.

The Company’s average realized sales price for crude oil and condensate in 2003 was $26.15 per barrel compared to $24.20 in 2002. The U.S. average crude oil sales price was essentially flat with 2002 and averaged $24.22 per barrel. Light oil production in Canada was sold at an average of $27.68 per barrel in 2003, up 21% from 2002. Heavy Canadian oil sold at $12.36 per barrel in 2003, 27% lower than in 2002. The average 2003 sales prices for offshore and synthetic oil production in Canada were $27.08 per barrel and $24.97 per barrel, respectively. Offshore prices were 7% higher than 2002, but synthetic crude was lower by 3%. The average sales price in the U.K. increased by 21% to $29.59 per barrel. Ecuador production was sold at an average of $22.99 per barrel, which was 17% above the average for 2002. New production from the West Patricia field in Malaysia brought an average of $29.42 per barrel in 2003.

In association with the higher oil prices, the sales prices for natural gas also strengthened in the Company’s gas producing markets during each of the past two years. The Company’s average realized sales price for North American natural gas was $6.34 per thousand cubic feet (MCF) in 2004, 24% higher than the previous year. The 2003 price was reduced by $.21 per MCF because of the Company’s hedging program in the U.S. and Canada.

In 2003, the average natural gas sales price realized by the Company in North America was $5.13 per MCF, 57% higher than in 2002. In the U.S., natural gas sales prices averaged $5.29 per MCF in 2003, up 57% compared to 2002. Canadian gas prices increased 73% to an average of $4.47 per MCF. Natural gas was sold in the U.K. at an average of $3.50 per MCF, 27% higher than the 2002 average.

Based on 2004 volumes and deducting taxes at marginal rates, each $1 per barrel and $.10 per MCF fluctuation in prices would have affected earnings from exploration and production operations by $21 million and $2.5 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.

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Production expenses were $249 million in 2004, $189.6 million in 2003 and $189.3 million in 2002. These amounts are shown by major operating area on pages F-34 and F-35 of this Form 10-K report. Costs per equivalent barrel excluding discontinued operations during the last three years are shown in the following table.

The higher costs in the United States in 2004 were due primarily to lower production and higher costs for properties on the continental shelf of the Gulf of Mexico. The lower U.S. cost in 2003 was due to both higher production and less well servicing costs. Higher average Canadian costs excluding synthetic oil in 2004 were caused by lower natural gas production and a higher average foreign exchange rate. The decline in Canadian unit rate in 2003 was caused by a decrease in offshore costs plus the effects of higher offshore production. The increase in unit costs for Canadian synthetic oil operations in 2004 was attributable to a combination of higher maintenance and energy costs and a higher foreign exchange rate; the 2003 increase per unit was due to the same factors as 2004, plus the effects of lower barrels produced. Lower average costs in the U.K. in each of the last two years were mainly due to sale of high-cost properties, including “T” Block in 2004 and Ninian and Columba in 2003. The increase in the unit rate in Malaysia in 2004 compared to 2003 was primarily due to higher manpower, fuel and export duty costs. Production expense increases per unit in Ecuador were mostly attributable to higher transportation costs associated with the heavy oil pipeline that commenced operations in the second half of 2003.

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-34 and F-35 on this Form 10-K report. Certain of the expenses are included in the capital expenditures total for exploration and production activities.

Dry hole costs were $50.3 million higher in 2004 than 2003 because of more costs for unsuccessful drilling on the Scotian Shelf, offshore Eastern Canada, and in Block K Malaysia. Dry holes were $29.2 million lower in 2003 than 2002 primarily due to more drilling success in deepwater Malaysia blocks in the later year. Geological and geophysical expenses were $2.8 million lower in 2004, mostly due to lower seismic acquisition and interpretation work offshore Eastern Canada, partially offset by higher seismic costs in Malaysia. Geological and geophysical costs were up $19.9 million in 2003 mostly due to 3D seismic acquisition and processing in Blocks SK 309 and PM 311 in Malaysia. Other exploration expenses were $2.5 million higher in 2004 than 2003 mainly due to more costs for Gulf of Mexico annual lease rentals and higher charges for work commitments on leases on the Scotian Shelf offshore Eastern Canada. Other exploration expenses were $3.2 million lower in 2003 because more administrative costs in Malaysia were charged to the production department after start-up of West Patricia field production in May. Undeveloped leasehold amortization increased by $1.7 million in 2004 and $1.2 million in 2003 because of lease acquisitions in each year in the Gulf of Mexico, plus the acquisition in 2004 of two exploration concessions in the deep waters offshore the Republic of Congo.

Costs of $2.6 million and $5 million were incurred in 2004 and 2002, respectively, to repair equipment and well damages caused by hurricanes in the Gulf of Mexico. These costs essentially represent amounts not recovered through insurance policies. The Company’s exploration and production operations also recorded a $12.6 million pretax cost in 2004 for a retrospective insurance premium related to past claims experience of the insurer.

Depreciation, depletion and amortization expense related to exploration and production operations totaled $241.5 million in 2004, $198.6 million in 2003 and $144.7 million in 2002. The $42.9 million increase in 2004 compared to 2003 was caused primarily by higher production at the Medusa and Habanero fields in the deepwater Gulf of Mexico and the West Patricia field in Block SK 309 Malaysia. The $53.9 million increase in 2003 was mostly due to higher production in Canada and start-up of the West Patricia field in 2003.

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The exploration and production business recorded expense of $9.9 million in 2004 and $9.7 million in 2003 for accretion on discounted abandonment liabilities following the adoption of SFAS No. 143 on January 1, 2003. Because the abandonment liabilities are carried on the balance sheet at a discounted fair value, accretion must be recorded annually so that the liability will be recorded at full value at the projected time of abandonment.

Property impairments occurred in the United States in 2003 and 2002. Impairment charges of $3 million in 2003 related to the writedown of the cost of a natural gas field in the Gulf of Mexico for a reserve reduction caused by poor well performance. The impairment in 2002 of $31.6 million was mostly related to writeoff of the remaining investment of $22.5 million in 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 until at least 2012. The remainder of the 2002 charge also related to impairments for poor natural gas well performance in the U.S.

The effective income tax rate for exploration and production operations was 32.7% in 2004, 31.2% in 2003, and 34.8% in 2002. The effective tax rates in 2004 and 2003 were lower than statutory rates partially due to recognition of deferred income tax benefits in Malaysia in each year. The 2004 deferred tax benefit of $31.9 million arose due to the expectation that temporary differences associated with exploration and other expenses incurred to-date in Block K Malaysia will be utilized to reduce future taxable income. An $11.4 million deferred tax benefit was recognized in 2003 for similar circumstances in Malaysia Blocks SK 309 and 311. These benefits had not been recognized in the income statement in previous years because the Company had established a deferred tax valuation allowance until such time that it became probable that these expenses would be utilized as deductions to reduce future taxable income. In 2004, Alberta reduced their tax rates for oil and gas companies. In 2003, both the Federal and Alberta governments of Canada reduced their tax rates for oil and gas companies. The rate reductions led to recognition of a $4.9 million benefit in 2004 and a $10.1 million tax benefit in 2003, mostly related to a reduction in deferred income tax liabilities. In addition, the effective tax rate in 2003 was favorable to 2002 due to sale of the Company’s interests in the Ninian and Columba fields in 2003. Profits on these fields were assessed Petroleum Revenue taxes in addition to normal corporation taxes; thus the sale of these fields reduced the overall effective tax rate in the U.K.

Approximately 53% of the Company’s U.S. proved oil reserves and 38% of the U.S. proved natural gas reserves are undeveloped. At December 31, 2004, about 98% of the total U.S. undeveloped reserves (on a barrel of oil equivalent basis) are associated with deepwater Gulf of Mexico fields. Almost 70% of these undeveloped reserves relate to the Front Runner field, which came on stream in December 2004. Seven of the eight wells at Front Runner were not completed and/or producing at year-end; these wells are expected to be brought into production sequentially during 2005 and early 2006. In addition, oil reserves in Block K in Malaysia of 40 million barrels at year-end 2004 are all undeveloped, pending completion of facilities and development drilling in future years. This field is projected to be on production in the second half of 2007. On a worldwide basis, the Company spent approximately $272 million in 2004, $280 million in 2003, and $239 million in 2002 to develop proved reserves. The Company expects to spend about $307 million in 2005, $558 million in 2006 and $422 million in 2007 to move currently undeveloped proved reserves to the developed category.

Refining and Marketing – The Company’s refining and marketing operations generated a profit of $81.9 million in 2004, after posting losses of $11.2 million in 2003 and $39.9 million in 2002. The R&M operating results improved markedly in 2004 because the Company was able to extract a higher gross margin from product sales in both the U.S. and U.K. markets. Although the price of crude oil, the primary refinery feedstock, was much more costly during 2004 than in 2003, the supplies of gasoline and certain other products remained tight during much of the year. Thus refining margins in both the U.S. and U.K. were much stronger during 2004. The Meraux refinery also ran more efficiently in 2004 than in 2003, and therefore, the costs of operations were spread over a larger number of crude oil barrels, benefiting margins on a per-unit basis. Murphy also enjoyed better profits from its Murphy USA retail station chain in 2004, essentially due to a combination of higher volumes sold, a better markup of gasoline prices compared to laid-in costs, and lower operating costs per gallon sold. The Company added 129 stations to its chain during 2004, an increase of 21% over the number of sites at year-end 2003. Sales volume per station increased more than 6% in 2004 compared to 2003.

The 2003 loss from R&M operations was lower than the 2002 loss by $28.7 million primarily due to better margins from the gasoline retail business in North America and the refining and marketing business in the United Kingdom. The Company’s U.S. refining margins were squeezed in 2003, primarily due to the high price of crude oil that the Company was not able to completely pass through to wholesale and other refinery customers. In addition to higher average fuel margins in 2003 at North American retail gasoline stations, the Company’s profits from merchandise sales at these gasoline stations were also better than in 2002.

Geographically, the North American R&M operations had income of $53.4 million in 2004 after incurring losses of $21.2 million in 2003 and $39.2 million in 2002. North American operations include refining activities in the United States and marketing activities in the United States and Canada. Operations in the U.K. generated a record profit of $28.5 million in 2004, compared to a profit of $10 million in 2003 and a $.7 million loss in 2002.

Unit margins (sales realizations less costs of crude oil and other feedstocks, refinery operating and depreciation expenses and transportation to point of sale) averaged $2.25 per barrel in North America in 2004, $1.60 in 2003 and $.80 in 2002. North American product sales volumes increased 31% to a record 301,801 barrels per day in 2004, following a 30% increase in 2003. Sales volumes through the Company’s retail gasoline network at Wal-Mart stores grew steadily throughout 2004 and 2003.

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Unit margins in the United Kingdom averaged $4.85 per barrel in 2004, $2.86 per barrel in 2003 and $1.70 per barrel in 2002. Sales of petroleum products were up 6% in 2004 following a 2% increase in 2003. The 2004 increase was primarily caused by higher volumes sold in both the retail and cargo market, while the increase in 2003 was mostly attributable to cargo market sales growth.

U.S. refining and marketing operations were experiencing losses in early 2005 as this business was unable at that time to pass along the higher costs of crude oil feedstocks to its customers buying refined products such as gasoline and diesel.

Based on sales volumes for 2004 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 $32.7 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, interest expense, foreign exchange gains and losses, and corporate overhead not allocated to operating functions, were $97.8 million in 2004, $13.8 million in 2003 and $23.6 million in 2002. Net after-tax corporate costs in 2004 were $84 million higher than in 2003. The increase was related to unfavorable foreign exchange losses, higher administrative costs, higher net interest expense and unfavorable income taxes. Due to a much weaker U.S. dollar compared to the Canadian dollar, pound sterling and the Euro, the Company incurred after-tax losses of $18.6 million for foreign exchange in 2004 compared to a $5.4 million profit in 2003. The exchange losses were mostly attributable to foreign subsidiaries with non-U.S. dollar functional currencies holding a significant level of U.S. dollars that experienced devaluation against these other currencies during the last half of 2004. Administrative expenses were $8.5 million higher in 2004, mostly due to higher costs of corporate compliance under the Sarbanes-Oxley Act and higher salaries, retirement and other benefits and other compensation expenses. Net interest expense was $13.5 million higher in 2004, mostly due to lower interest being capitalized on U.S. oil and gas developments and U.S. refinery expansion projects that are now completed and the assets in service. Income tax expense in 2004 was unfavorable by $43 million in the corporate area primarily due to a $27.5 million withholding tax incurred on a $550 million dividend paid to the Company by its Canadian subsidiary, and a $20.1 million tax benefit in 2003 from settlement of previous years’ income tax audit issues. The Company earned $13.3 million more interest income in 2004 mostly related to holding larger balances of invested cash for a portion of the year after selling most of its conventional oil and gas properties in Western Canada.

Net after-tax corporate costs were $9.8 million lower in 2003 than in 2002 mainly due to a $20.1 million benefit from settlement of previous years’ U.S. income tax audit issues and lower net interest expense. These cost savings were partially offset by higher general and administrative expenses, including costs related to the Company’s retirement and incentive compensation plans.

Capital Expenditures

As shown in the selected financial data on page 8 of this Form 10-K report, capital expenditures for continuing operations, including discretionary exploration expenditures, were $975.4 million in 2004 compared to $906.1 million in 2003 and $774.8 million in 2002. These amounts included $147.9 million, $97.9 million and $110.4 million of exploration costs that were expensed. Capital expenditures for exploration and production activities totaled $839.2 million in 2004, 86% of the Company’s total capital expenditures for the year. Exploration and production capital expenditures in 2004 included $16.6 million for acquisition of undeveloped leases, $54 million and $67.3 million for acquisition of unproved and proved properties, respectively, in the Seal area in Western Canada, $268.1 million for exploration activities, and $433.2 million for development projects. Development expenditures included $86.3 million for development of deepwater discoveries in the Gulf of Mexico; $104.6 million for the West Patricia and Kikeh fields in Malaysia; $33.7 million for the Terra Nova and Hibernia oil fields, offshore Newfoundland; $99.6 million for expansion of synthetic oil operations at the Syncrude project in Canada; and $68.1 million for Western Canada heavy oil and natural gas projects. Exploration and production capital expenditures are shown by major operating area on page F-33 of this Form 10-K report.

Refining and marketing capital expenditures totaled $134.7 million in 2004, compared to $215.4 million in 2003 and $234.7 million in 2002. These amounts represented 14%, 24% and 30% of capital expenditures for continuing operations of the Company in 2004, 2003 and 2002, respectively. Refining capital spending was $46.1 million in 2004 compared to $130.8 million in 2003 and $150.1 million in 2002. In 2004, the Company completed the construction of a green gasoline unit at its Superior, Wisconsin refinery. In 2003, it finished the expansion of the Meraux, Louisiana refinery, which included building a hydrocracker unit to meet future clean fuel specifications and expanding the crude oil processing capacity of the plant to 125,000 barrels per day. Capital expenditures on the Superior refinery unit green gasoline were $18 million in 2004 and $5.5 million in 2003. Capital expenditures related to the Meraux expansion project amounted to $5.5 million in 2004, $69 million in 2003 and $116.2 million in 2002. Marketing expenditures amounted to $88.6 million in 2004 and $84.6 million in 2003 and 2002. 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 added 129 total stations to this retail network in 2004, 119 in 2003 and 125 in 2002.

Cash Flows

Cash provided by continuing operations was $1,035.1 million in 2004, $501.1 million in 2003 and $372.2 million in 2002. The increase in cash provided in 2004 was primarily due to higher crude oil and refined product sales volumes, and higher sales prices for crude oil, natural gas and refined products. Cash provided by continuing operations was reduced by expenditures for refinery turnarounds and abandonment of oil and gas properties totaling $18.6 million in 2004, $66.1 million in 2003 and $14.8 million in 2002. Scheduled plant-wide turnarounds occurred at both U.S. refineries in 2003.

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Cash proceeds from property sales other than from discontinued operations were $60.4 million in 2004, $188.6 million in 2003 and $68.1 million in 2002. The 2004 property sales included the disposal of the “T” Block field in the U.K. North Sea and certain U.S. onshore gas properties and U.S. marketing terminals while 2003 included disposal of the Ninian and Columba fields in the U.K. and various oil and gas assets in Canada and the Gulf of Mexico. Disposals of properties classified as discontinued operations brought in net cash proceeds of $583 million in 2004. This disposal included most of the Company’s conventional oil and gas properties in Western Canada. During 2003 and 2002, the Company borrowed under notes payable and other long-term debt arrangements primarily to fund a portion of the Company’s development capital expenditures; these borrowings provided $309.7 million of cash in 2003 and $407.6 million in 2002. Cash proceeds from stock option exercises and employee stock purchase plans amounted to $3.2 million in 2004, $3.6 million in 2003 and $25.1 million in 2002.

Property additions and dry hole costs used cash of $938.4 million in 2004, $868.9 million in 2003 and $765.9 million in 2002. A heavy oil property acquisition in Canada, plus higher heavy oil development spending and higher exploration drilling in Malaysia were the primary reasons for the increase in 2004. More field development expenditures in the deepwater Gulf of Mexico and at the West Patricia and Kikeh fields in Malaysia mostly accounted for the 2003 increase. The Company used a portion of the proceeds of asset dispositions classified as discontinued operations to repay a significant portion of long-term debt in 2004. Total paydown of debt was $495 million during 2004. Cash outlays for debt repayment during 2003 and 2002 were $76.8 million and $57.8 million, respectively. Cash of $17.9 million was invested in 2004 in U.S. government securities with maturities greater than 90 days. Cash used for dividends to stockholders was $78.2 million in 2004, $73.5 million in 2003 and $70.9 million in 2002. The Company raised its annualized dividend rate from $.80 per share to $.90 per share beginning in the third quarter of 2004. The Company had previously increased the annualized dividend rate from $.75 per share to $.80 per share at mid-year 2002.

Financial Condition

Year-end working capital totaled $424.4 million in 2004, $228.5 million in 2003 and $136.3 million in 2002. 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 $219.1 million below fair value at December 31, 2004. Cash and cash equivalents at the end of 2004 totaled $535.5 million compared to $252.4 million a year ago and $165 million at the end of 2002.

Long-term debt was reduced by $477 million during 2004 and totaled $613.3 million at the end of the year, 18.8% of total capital employed. Long-term debt included $15.6 million of nonrecourse debt incurred in connection with the Hibernia oil field. The long-term debt reduction in 2004 was achieved primarily using the proceeds of asset dispositions in Western Canada. Long-term debt totaled $1.09 billion at the end of 2003 compared to $862.8 million at December 31, 2002. Stockholders’ equity was $2.65 billion at the end of 2004 compared to $1.95 billion a year ago and $1.59 billion at the end of 2002. A summary of transactions in stockholders’ equity accounts is presented on page F-6 of this Form 10-K report.

Other significant changes in Murphy’s year-end 2004 balance sheet compared to 2003 included a $252.7 million increase in accounts receivable, which was primarily caused by sales of higher volumes of crude oil and refined products at higher average prices near the end of 2004 compared to the 2003 year-end. Crude oil and blend stocks inventory was $24.4 million more than 2003 mostly because of 1.5 million barrels of unsold crude oil inventory in Ecuador. The Company did not receive its allocated share of Ecuadorian production to sell for approximately the last seven months of 2004 due to a dispute with the area operator over our new transportation and marketing arrangements. Short-term deferred income tax assets increased $10.5 million at year-end 2004 due mostly to a deferred tax benefit recorded in 2004 in Ecuador; this benefit offset a current tax charge related to a temporary difference associated with the timing of income reported for book and tax purposes. Net property, plant and equipment increased by $154.8 million as capital expenditures during the year were larger than the cost of properties disposed and the additional depreciation and amortization expensed. Goodwill related to the acquisition of Beau Canada in 2000 decreased by $21.3 million as a portion of goodwill was allocated to the cost pool for the sale of Western Canada properties in 2004. Deferred charges and other assets increased $21.6 million in 2004 due to the net change in long-term deferred tax assets for Malaysian operations. Current maturities of long-term debt declined by $16.5 million primarily because of paydown of Hibernia nonrecourse loans. Accounts payable rose by $237.7 million mostly due to the higher costs of purchased crude oil and gasoline at year-end 2004 compared to 2003. Income taxes payable increased $158.4 million at year-end 2004 due to combination of higher operating profits in 2004 and a liability associated with settlement of all Beau Canada Exploration acquisition financing matters with the Canadian tax authorities during early 2005. Other taxes payable increased $27.2 million mostly due to higher sales, use and excise taxes owed at year-end 2004 compared to 2003. Deferred income tax liabilities increased $155.3 million in 2004 due mostly to higher accelerated depreciation taken in tax returns based on 2004 property acquisitions and other capital expenditures. The liability associated with asset retirements dropped by $50.5 million mostly due to sales of Western Canada conventional oil and gas properties and “T” Block in the North Sea during 2004. Accrued major repair costs increased by $23.7 million primarily based on accruing additional costs for future turnarounds of the company’s three refineries.

Murphy had commitments of $727 million for capital projects in progress at December 31, 2004, including $28 million for costs to develop deepwater Gulf of Mexico fields, $63 million for continued expansion of synthetic oil operations in Canada, $394 million for field development and future work commitments in Malaysia, and $37 million for exploration drilling in Congo.

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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. At December 31, 2004, the Company had access to short-term and long-term revolving credit facilities in the amount of $700 million. None of the revolving facilities had been drawn at year-end 2004. The most restrictive covenants under these facilities limit the Company’s long-term debt to capital ratio (as defined in the agreements) to 60%. At December 31, 2004, the long-term debt to capital ratio was approximately 19%. The Company also has unused uncommitted credit lines of approximately $392 million at December 31, 2004. 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 E to the consolidated financial statements. At present, the Company does not anticipate utilizing a significant amount of its long-term borrowing capacity in 2005 as normal cash flow from operations is expected to cover the Company’s capital expenditure program. At March 1, 2005 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 13.4 to 1 in 2004, 6.1 to 1 in 2003 and 2.7 to 1 in 2002.

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 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, five 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.

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. Although regulatory authorities may require more costly alternatives than the proposed processes, the cost of such potential alternative processes is not expected to exceed the accrued liability by a material amount.

The U.S. Environmental Protection Agency (EPA) currently considers the Company to be 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. Based on currently available

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information, the Company believes that it is a de minimus party as to ultimate responsibility at both Superfund sites. 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 two sites or other Superfund sites. The Company believes that its share of the ultimate costs to clean-up the two Superfund sites will be immaterial and will not have a material adverse effect on its net income, financial condition or liquidity 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 net income, financial condition or liquidity in a future period.

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, 2004.

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 $6.6 million in 2004. 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 $60.3 million in 2004 and are projected to be $35.9 million in 2005.

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 have generally strengthened during the last two years, 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 G on page F-14 of this Form 10-K report, Murphy adopted the Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standards (SFAS) 143, Accounting for Asset Retirement Obligations, effective January 1, 2003. Upon adoption of SFAS No. 143, the Company recorded an after-tax charge of $7 million, which was reported as the cumulative effect of a change in accounting principle.

The Financial Accounting Standards Board (FASB) has issued Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), Share Based Payment, which replaces SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. SFAS No. 123 (revised 2004) requires that the cost resulting from all share-based payment transactions be recognized as an expense in the financial statements using a fair-value-based measurement method over the periods that the awards vest. The statement will be effective for the Company beginning in its third quarter which starts on July 1, 2005. The Company is currently evaluating which fair value measurement method to use and whether to use the modified retrospective application or modified prospective application upon adoption. Although the Company currently uses the intrinsic-value approach of Accounting Principles Board No. 25 to account for stock options, it provides pro forma disclosures in Note A as if SFAS No. 123 was currently being applied.

The FASB has issued for comment a proposed FASB Staff Position (FSP) 19-a to provide guidance on the accounting for exploratory well costs and to propose an amendment to SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies. The guidance in FSP 19-a will apply to companies that use the successful efforts method of accounting as described in SFAS No. 19. This proposed FSP would clarify that exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating validity of the project. The guidance in this FSP is to be applied in the first reporting period beginning after the date the FSP is finalized. The guidance will be applied prospectively to existing and newly-capitalized exploratory well costs. However, any capitalized well costs that do not meet the requirements of the FSP must be written off upon its adoption. The proposed FSP as written requires additional disclosures related to capitalized costs.

The Emerging Issues Task Force (EITF) has issued EITF 03-13, Applying the Conditions in Paragraph 42 of SFAS No. 144 in Determining Whether to Report Discontinued Operations. The EITF generally believes that current practice with respect to applying the criteria in paragraph 42 of

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SFAS No. 144 has not been applied consistently and has not resulted in broadening the reporting of asset dispositions as discontinued operations. EITF 03-13 contains further guidance for evaluating the cash flows of the component sold and what constitutes significant continuing involvement. This standard must be applied to all asset disposal transactions occurring after January 1, 2005. EITF 03-13 may lead in certain industries to more asset disposals being reported as discontinued operations in future periods. However, in the oil and gas industry, it may cause more asset disposals to continue to be classified as continuing operations due to clarification of what constitutes continuing involvement.

In October 2004, the President of the United States signed into law the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (the “Act”). The FASB issued FSP 109-1 in December 2004 to provide guidance on the application of SFAS No. 109, Accounting for Income Taxes, to the provision within the Act that provides, beginning in 2005, a tax deduction of up to 9% on qualified production activities. FSP 109-1 concludes that the deduction should be accounted for as a special deduction in accordance with SFAS 109, which means that the tax benefit is recognized as realized, rather than as a one-time benefit due to a reduction of deferred tax liabilities. This FSP was effective upon issuance. The Company cannot predict what impact the Act will have on net income in future periods.

SFAS No. 151, Inventory Costs was issued by the FASB in November 2004. This statement amends Accounting Research Bulletin No. 43, to clarify that abnormal amounts of idle facility expense, freight, handling costs, and wasted materials should be recognized as current-period charges, and it also requires that allocation of fixed production overheads be based on the normal capacity of the related production facilities. The provisions of this statement will be effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The provisions of this statement will be applied prospectively. The Company does not expect the adoption of this statement to have a significant impact on its results of operations.

The FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets an amendment of APB Opinion No. 29, in December 2004. This statement addresses the measurement of exchanges of nonmonetary assets and eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. The provisions of SFAS No. 153 will be effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The provisions of this statement will be applied prospectively. The Company does not expect the adoption of this statement to have a significant impact on its results of operations.

In 2004 the FASB reviewed whether mineral interests in properties (mineral leases) held by oil and gas companies should be recorded and disclosed as intangible assets under the guidance of SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. After consideration of the matter, the FASB issued a staff position stating that drilling and mineral rights of oil and gas producing entities that are within the scope of SFAS 19 are not subject to the intangible asset classification and disclosure rules of SFAS No. 142. The staff position is consistent with the Company’s present accounting practices and had no effect on its financial statements or disclosures.

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. The most significant of these accounting policies are described below.

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In some cases, a determination of whether a drilled well has found proved reserves can not be made immediately. This is generally due to the need for a major capital expenditure to produce and/or evacuate the hydrocarbon(s) found. The determination of whether to make such a capital expenditure is, in turn, usually dependent on whether additional exploratory wells find a sufficient quantity of additional reserves. When further drilling is firmly planned or in progress, the Company holds these well costs in Property, Plant and Equipment until the drilling is completed. In cases where oil and gas reserves have been found but can not be classified as proved within one year after an exploratory well is drilled, the Company will hold such well costs in Property when classification of proved reserves are dependent upon, and we are actively seeking, approval of a development plan by a foreign government.

Costs of all exploration wells in progress at year-end 2004 amounted to $29 million. Through early March 2005, these wells were either still drilling or successfully found hydrocarbon deposits, certain of which are still being evaluated by the Company.

Based on the time required to complete further exploration and appraisal drilling in areas where hydrocarbons have been found but proved reserves have not been booked, dry hole expense may be recorded one or more years after the original drilling costs are incurred. Dry hole expenses related to wells drilled in prior years were $13.2 million in 2004 and $10.7 million in 2002.

In making its impairment assessments involving exploration and production property and equipment, the Company must make a number of projections involving future oil and natural gas sales prices, future production volumes, and future capital and operating costs. Due to the volatility of world oil and gas markets, the actual sales prices for oil and natural gas have often been quite different from the Company’s projections. Estimates of future oil and gas production and sales volumes are based on a combination of proved and risked probable and possible reserves. Although the estimation of reserves and future production is uncertain, the Company believes that its estimates are reasonable; however, there have been cases where actual production volumes were higher or lower than projected and the timing was different than the original projection. The Company adjusts reserve and production estimates as new information becomes available. The Company generally projects future costs by using historical costs adjusted for both assumed long-term inflation rates and known or expected changes in future operations. Although the projected future costs are considered to be reasonable, at times, costs have been higher or lower than originally estimated. In making impairment assessments for refining and marketing property and equipment, future margins for the refining and marketing business are generally projected based on historical results adjusted for known or expected changes in future operations. Although the Company is not aware of any property carrying values that are impaired at December 31, 2004, one or a combination of factors such as significantly lower future sales prices, significantly lower future production, significantly higher future costs, or significantly lower future margins for refining and marketing, could lead to impairment expenses in future periods. Based on these unknown future factors as described herein, the Company can not predict the amount or timing of impairment expenses that may be recorded in the future.

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Contractual obligations and guarantees – The Company is obligated to make future cash payments under borrowing arrangements, operating leases, purchase obligations and other long-term liabilities. In addition, the Company expects to extend certain operating losses beyond the minimum contractual period. Total payments due after 2004 under such contractual obligations and arrangements are shown below.

In addition to the obligations as of December 31, 2004 as reflected in the above table, in early 2005 the Company entered into a floating, production, storage and offloading (FPSO) vessel lease and a dry tree unit construction contract associated with development of the Kikeh field in Block K Malaysia. Total Kikeh field development costs are expected to be $1.9 billion.

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 as of December 31, 2004 that expire in future periods is shown below.

Material off-balance sheet arrangements – The Company occasionally utilizes off-balance sheet arrangements for operational or funding purposes. The most significant of these arrangements at year-end 2004 involve an oil and natural gas processing contract and a hydrogen purchase contract. The processing contract provides crude oil and natural gas processing capacity for oil and natural gas production from the Medusa field in the Gulf of Mexico. Under the contract, the Company pays a specified amount per barrel of oil equivalent for processing its oil and natural gas through the facility. If actual oil and natural gas production processed through the facility through 2009 is less than a specified quantity, the Company must make additional quarterly payments up to an agreed minimum level that varies over time. The Company has a contract to purchase hydrogen for the Meraux refinery through 2019. The contract requires a monthly minimum base facility charge whether or not any hydrogen is purchased. Payments under both these agreements are recorded as operating expenses when paid. Future required minimum annual payments under both of these arrangements are included in the contractual obligation table shown above.

Outlook

Prices for the Company’s primary products are often quite volatile. A strong global economy, political uncertainty in Iraq and the Middle East, and effective price management practices utilized by OPEC led to high oil prices during 2004 and early 2005. Natural gas prices also were strong in 2004 and early 2005, mainly due to the high price of crude oil and also because demand for the product often outstrips supply in the short term. Due to the volatility of worldwide crude oil prices and North American natural gas prices routine monitoring of spending plans is required.

The Company’s capital expenditure budget for 2005 was prepared during the fall of 2004 and provides for capital expenditures of $1.066 billion. Of this amount, $887 million or 83%, is allocated for exploration and production. Geographically, 19% of the exploration and production budget is allocated to the United States, including $57 million for development of deepwater projects in the Gulf of Mexico; another 24% is allocated to Canada, including $68 million for development of heavy oil fields and $78 million for further expansion of synthetic oil operations; 49% is allocated to exploration and development in Malaysia, including $141 million for field development at Kikeh in Block K; and the remaining 8% is planned for other areas, including Ecuador, the United Kingdom and the Republic of Congo. Budgeted refining and marketing capital expenditures for 2005 are $171 million, including $146 million in North America and $25 million in the United Kingdom. Planned spending in North America includes funds to build 150 additional gasoline stations at Wal-Mart sites. Capital and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and actual cash flow during 2005.

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The Company currently does not anticipate a significant increase in long-term borrowings during 2005. Although Murphy’s 2005 Budget includes a robust amount of capital spending, the Company expects normal operating cash flows to be sufficient to cover planned spending. It is possible that long-term debt could increase significantly in 2005, especially if cash flows are adversely affected in the near term by significantly weaker oil and natural gas sales prices and continued weak refining and marketing margins such as those experienced in early 2005. Rising crude prices in early 2005 squeezed refining and marketing margins; this business was experiencing losses in early 2005.

The Company has made a significant oil discovery in Block K offshore Sabah, Malaysia at a field named Kikeh. A field development plan, as approved by the Company’s Board of Directors and the Malaysian authorities, calls for gross development costs of $1.9 billion, which includes $.5 billion of lease costs for an FPSO. The Company has an 80% working interest in the field. It is likely that a significant portion of the Company’s share of funding for field development in 2006 will come from borrowed capital. First production from the Kikeh field offshore Sabah is estimated to occur in the second half of 2007.

Murphy’s oil and natural gas production is expected to grow in 2005. Production from the Front Runner deepwater Gulf of Mexico field will ramp up in 2005 and development drilling in Western Canada at Seal should lead to higher heavy oil production. The combination of higher Front Runner and Seal production is expected to more than offset normal production declines elsewhere. Total production for 2005 is projected to average approximately 130,000 barrels of oil equivalent per day.

Murphy Oil and certain of its subsidiaries maintain defined benefit retirement plans covering most of its full-time employees. Due to a reduction in bond yields during 2004, the Company has reduced the primary plans’ discount rate from 6.25% in 2004 to 6.00% in 2005. Although the Company presently assumes a return on plan assets of 7.5% for the primary plan, it periodically reconsiders the appropriateness of this and other key assumptions. The smoothing effect of current accounting regulations tend to buffer the current year’s pension expense from wide swings in liabilities and asset returns. The effect of a lower discount rate and a growing employee population will lead to higher pension expense in 2005. The Company’s annual retirement plan expense is estimated to increase by about $1.4 million for 2005 compared to 2004. In 2005, the Company is expecting to fund payments of approximately $12.1 million into various retirement plans and $2.9 million for postretirement plans. The Company could be required to make additional and more significant funding payments to retirement plans in future years.

Forward-Looking Statements

This Form 10-K report, including documents incorporated by reference here, contains statements of the Company’s expectations, intentions, plans and beliefs that are forward-looking and are dependent on certain events, risks and uncertainties that may be outside of the Company’s control. These forward-looking statements are made in reliance upon the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Actual results and developments could differ materially from those expressed or implied by such statements due to a number of factors including those described in the context of such forward-looking statements as well as those contained in the Company’s January 15, 1997 Form 8-K report on file with the U.S. Securities and Exchange Commission.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note A to the consolidated financial statements, Murphy makes limited use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.

Murphy was a party to natural gas price swap agreements at December 31, 2004 for a remaining notional volume of 2.2 million MMBTU that are intended to hedge the financial exposure of its Meraux, Louisiana refinery to fluctuations in the future price of a portion of natural gas to be purchased for fuel in 2005 and 2006. In each month of settlement, the swaps require Murphy to pay an average natural gas price of $3.35 per MMBTU and to receive the average NYMEX price for the final three trading days of the month. At December 31, 2004, the estimated fair value of these agreements was recorded as an asset of $6.1 million. A 10% increase in the average NYMEX price of natural gas would have increased this asset by $1.3 million, while a 10% decrease would have reduced the asset by a similar amount.

At December 31, 2004, the Company was a party to forward sale contracts covering 2,000 barrels per day in heavy oil sales during 2005 and 4,000 barrels per day in 2006. The contracts are intended to hedge the financial exposure of the Company’s heavy oil sales in Canada during the respective contract period and are priced at $29.00 per barrel in 2005 and $25.23 per barrel in 2006. At December 31, 2004, the estimated fair value of these agreements was recorded as an asset valued at $.6 million. A 10% increase in the price of Canadian heavy oil at the Hardisty terminal in Canada would have decreased this asset by $5.6 million, while a 10% decrease would have increased this asset by a similar amount.

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Information required by this item appears on pages F-1 through F-38, which follow page 29 of this Form 10-K report.

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

Item 9A. CONTROLS AND PROCEDURES

Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by Murphy to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

Based on the Company’s evaluation as of the end of the period covered by the filing of this Annual Report on Form 10-K, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

Murphy’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control – Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2004. Our report is included on F-2 of the annual report. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included on page F-2 of this annual report.

There were no significant changes in the Company’s internal controls over financial reporting that occurred during the fourth quarter of 2004 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B. OTHER INFORMATION

None

PART III

Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Certain information regarding executive officers of the Company is included on page 7 of this Form 10-K report. Other information required by this item is incorporated by reference to the Registrant’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 11, 2005 under the caption “Election of Directors.”

Murphy Oil has adopted a Code of Ethical Conduct for Executive Management, which can be found under the Corporate Governance and Responsibility tab at www.murphyoilcorp.com. Stockholders may also obtain free of charge a copy of the Code of Ethical Conduct for Executive Management by writing to the Company’s Secretary at P.O. Box 7000, El Dorado, AR 71731-7000. Any future amendments to or waivers of the Company’s Code of Ethical Conduct for Executive Management will be posted on the Company’s internet website.

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Item 11. EXECUTIVE COMPENSATION

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 11, 2005 under the captions “Compensation of Directors,” “Executive Compensation,” “Option Exercises and Fiscal Year-End Values,” “Option Grants,” “Compensation Committee Report for 2004,” “Shareholder Return Performance Presentation” and “Retirement Plans.”

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 11, 2005 under the captions “Security Ownership of Certain Beneficial Owners,” “Security Ownership of Management,” and “Equity Compensation Plan Information.”

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 11, 2005 under the caption “Audit Committee Report.”

PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

2. Financial Statement Schedules

3. Exhibits – The following is an index of exhibits that are hereby filed as indicated by asterisk (*), that are to be filed by an amendment as indicated by pound sign (#), or that are incorporated by reference. Exhibits other than those listed have been omitted since they either are not required or are not applicable.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 15, 2005 by the following persons on behalf of the registrant and in the capacities indicated.

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REPORT OF MANAGEMENT – CONSOLIDATED FINANCIAL STATEMENTS

The management of Murphy Oil Corporation is responsible for the preparation and integrity of the accompanying consolidated financial statements and other financial data. The statements were prepared in conformity with generally accepted U.S. accounting principles appropriate in the circumstances and include some amounts based on informed estimates and judgments, with consideration given to materiality.

An independent registered public accounting firm, KPMG LLP, has audited the Company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board and provides an objective, independent opinion about the fair presentation of the consolidated financial statements. The Board of Directors appoints the independent auditors; ratification of the appointment is solicited annually from the shareholders.

The Board of Directors appoints an Audit Committee annually to implement and to support the Board’s oversight function of the Company’s financial reporting, accounting policies, internal controls and independent registered public accounting firm. This Committee is composed solely of directors who are not employees of the Company. The Committee meets routinely with representatives of management, the Company’s audit staff and the independent registered public accounting firm to review and discuss the adequacy and effectiveness of the Company’s internal controls, the quality and clarity of its financial reporting, the scope and results of independent and internal audits, and to fulfill other responsibilities included in the Committee’s Charter. The independent registered public accounting firm and the Company’s audit staff have unrestricted access to the Committee, without management presence, to discuss audit findings and other financial matters.

Our report of management covering internal control over financial reporting and the associated report of independent registered public accounting firm can be found at F-2.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of Murphy Oil Corporation:

We have audited the accompanying consolidated balance sheets of Murphy Oil Corporation and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2004. In connection with our audits of the consolidated financial statements we also have audited financial statement Schedule II. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

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