SEC Filing - Murphy Oil Corporation

================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-K (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended DECEMBER 31, 1998 OR [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _________________ to __________ Commission file number 1-8590 MURPHY OIL CORPORATION (Exact name of registrant as specified in its charter) DELAWARE 71-0361522 (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification Number) 200 PEACH STREET, P. O. BOX 7000, EL DORADO, ARKANSAS 71731-7000 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (870) 862-6411 Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered COMMON STOCK, $1.00 PAR VALUE NEW YORK STOCK EXCHANGE THE TORONTO STOCK EXCHANGE SERIES A PARTICIPATING CUMULATIVE NEW YORK STOCK EXCHANGE PREFERRED STOCK PURCHASE RIGHTS THE TORONTO STOCK EXCHANGE 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. [_] Aggregate market value of the voting stock held by non-affiliates of the registrant, based on average price at January 29, 1999, as quoted by the New York Stock Exchange, was approximately $1,220,526,000. Number of shares of Common Stock, $1.00 Par Value, outstanding at January 29, 1999, was 44,952,042. Documents incorporated by reference: Portions of the Registrant's definitive Proxy Statement relating to the Annual Meeting of Stockholders on May 12, 1999, have been incorporated by reference in Part III herein. ================================================================================

MURPHY OIL CORPORATION TABLE OF CONTENTS - 1998 FORM 10-K REPORT Page Number ------ PART I Item 1. Business 1 Item 2. Properties 1 Item 3. Legal Proceedings 6 Item 4. Submission of Matters to a Vote of Security Holders 6 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters 7 Item 6. Selected Financial Data 7 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 8 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 19 Item 8. Financial Statements and Supplementary Data 19 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 19 PART III Item 10. Directors and Executive Officers of the Registrant 20 Item 11. Executive Compensation 20 Item 12. Security Ownership of Certain Beneficial Owners and Management 20 Item 13. Certain Relationships and Related Transactions 20 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 21 Exhibit Index 21 Signatures 23 i

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 the United States and the United Kingdom and pipeline and crude oil trading operations in Canada. 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, Marketing and Transportation." For reporting purposes, Murphy's exploration and production activities are subdivided into five geographic segments -- the United States, Canada, the United Kingdom, Ecuador, and all other countries; Murphy's refining, marketing and transportation activities are subdivided into three geographic segments -- the United States, the United Kingdom and Canada. Additionally, "Corporate and Other Activities" include interest income, interest expense and overhead not allocated to the segments. On December 31, 1996, Murphy completed a spin-off to its stockholders of its wholly owned farm, timber and real estate subsidiary, Deltic Farm & Timber Co., Inc. (reincorporated as "Deltic Timber Corporation"). The information appearing in the 1998 Annual Report to Security Holders (1998 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 relative to Murphy's operations, properties and business segments, including revenues by class of products and financial information by geographic area, are described on pages 7, F-8, F-19 through F-21, F-24 through F-26, and F-28 of this Form 10-K report and on pages 6 through 19 of the 1998 Annual Report. EXPLORATION AND PRODUCTION During 1998, Murphy's principal exploration and production activities were conducted in the United States and Ecuador by wholly owned Murphy Exploration & Production Company (Murphy Expro) and its subsidiaries, in western Canada and offshore eastern Canada by wholly owned Murphy Oil Company Ltd. (MOCL) and its subsidiaries, and in the U.K. North Sea and the Atlantic Margin by wholly owned Murphy Petroleum Limited. Murphy's crude oil and natural gas liquids production in 1998 was in the United States, Canada, the United Kingdom and Ecuador; its natural gas was produced and sold in the United States, Canada and the United Kingdom. MOCL owns a 5% interest in Syncrude Canada Ltd., which extracts synthetic crude oil from oil sand deposits in northern Alberta. Subsidiaries of Murphy Expro conducted exploration activities in various other areas including the Falkland Islands, China, Ireland, the Faroe Islands, Spain, Philippines, Peru and Pakistan. Murphy's estimated net quantities of proved oil and gas reserves and proved developed oil and gas reserves at December 31, 1995, 1996, 1997 and 1998 by geographic area are reported on page F-23 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. 1

Net crude oil, condensate, and gas liquids production and net natural gas sales by geographic area with weighted average sales prices for each of the five years ended December 31, 1998, are shown on page 21 of the 1998 Annual Report. Production costs for the last three years in U.S. dollars per equivalent barrel produced are discussed on page 11 of this Form 10-K report. For purposes of these computations, natural gas 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-22 through F-27 of this Form 10-K report. At December 31, 1998, Murphy held leases, concessions, contracts or permits on nonproducing and producing acreage as shown by geographic area in the following table. Gross acres are those in which all or part of the working interest is owned by Murphy; net acres are the portions of the gross acres applicable to Murphy's working interest. NONPRODUCING PRODUCING TOTAL -------------- ----------------- -------------- AREA (THOUSANDS OF ACRES) GROSS NET GROSS NET GROSS NET - - ------------------------- ----- ----- ----- ----- ----- ----- United States - Onshore 5 3 39 20 44 23 - Gulf of Mexico 832 482 369 136 1,201 618 - Frontier 117 40 -- -- 117 40 ------ ------ ----- --- ------ ------ Total United States 954 525 408 156 1,362 681 ------ ------ ----- --- ------ ------ Canada - Onshore 813 582 1,084 155 1,897 737 - Offshore 941 178 5 -- 946 178 - Oil sands 225 54 13 4 238 58 ------ ------ ----- --- ------ ------ Total Canada 1,979 814 1,102 159 3,081 973 ------ ------ ----- --- ------ ------ United Kingdom 1,439 461 78 11 1,517 472 Ecuador -- -- 494 99 494 99 China 563 253 -- -- 563 253 Falkland Islands 401 100 -- -- 401 100 Ireland 896 224 -- -- 896 224 Malaysia 6,498 5,319 -- -- 6,498 5,319 Pakistan 3,795 3,795 -- -- 3,795 3,795 Philippines 3,695 2,956 -- -- 3,695 2,956 Spain 434 136 -- -- 434 136 Tunisia 109 36 -- -- 109 36 ------ ------ ----- --- ------ ------ Total 20,763 14,619 2,082 425 22,845 15,044 ====== ====== ===== === ====== ====== Oil and gas wells producing or capable of producing at December 31, 1998, are summarized in the following table. Gross wells are those in which all or part of the working interest is owned by Murphy. Net wells are the portions of the gross wells applicable to Murphy's working interest. OIL WELLS GAS WELLS -------------------- -------------------- COUNTRY GROSS NET GROSS NET - - ------- ----- ------ ----- ------ United States 323 143.5 272 106.7 Canada 4,173 827.0 815 286.0 United Kingdom 98 12.3 21 1.5 Ecuador 53 10.6 -- -- ----- ----- ----- ----- Total 4,647 993.4 1,108 394.2 ===== ===== ===== ===== Wells included above with multiple completions and counted as one well each 87 41.1 90 64.7 2

Murphy's net wells drilled in the last three years are summarized in the following table. UNITED UNITED STATES CANADA KINGDOM ECUADOR OTHER TOTAL ------------- ------------- ------------- ------------- ------------- ------------- PRO- PRO- PRO- PRO- PRO- PRO- DUCTIVE DRY DUCTIVE DRY DUCTIVE DRY DUCTIVE DRY DUCTIVE DRY DUCTIVE DRY ------- --- ------- --- ------- --- ------- --- ------- --- ------- --- 1998 - - ---- Exploratory 9.0 .8 4.8 7.5 -- -- -- -- -- 1.0 13.8 9.3 Development .6 -- 5.4 -- 1.9 -- 1.2 -- -- -- 9.1 -- 1997 - - ---- Exploratory 7.6 6.8 15.8 8.3 .5 .6 -- -- .4 1.0 24.3 16.7 Development 2.9 -- 83.0 -- .9 .3 1.6 -- -- -- 88.4 .3 1996 - - ---- Exploratory 13.8 3.9 5.3 4.0 -- 1.1 -- -- .4 -- 19.5 9.0 Development 4.6 -- 70.2 2.5 1.0 .1 2.2 -- -- -- 78.0 2.6 Murphy's drilling wells in progress at December 31, 1998, are summarized below. EXPLORATORY DEVELOPMENT TOTAL ---------------- -------------- ---------------- COUNTRY GROSS NET GROSS NET GROSS NET - - ------- ----- --- ----- --- ----- --- United States 2 .8 1 -- 3 .8 Canada 1 .5 2 .2 3 .7 United Kingdom - - 3 .3 3 .3 Ecuador - - 1 .2 1 .2 -- --- -- --- -- --- Total 3 1.3 7 .7 10 2.0 == === == === == === Additional information about current exploration and production activities is reported on pages 1 through 15 of the 1998 Annual Report. REFINING, MARKETING AND TRANSPORTATION Murphy Oil USA, Inc. (MOUSA), a wholly owned subsidiary, owns and operates two refineries in the United States. The Meraux, Louisiana refinery is located on fee land and on two leases that expire in 2010 and 2021, at which times the Company has options to purchase the leased acreage at fixed prices. The refinery at Superior, Wisconsin is located on fee land. Murco Petroleum Limited (Murco), a wholly owned U.K. subsidiary serviced by Murphy Eastern Oil Company, has an effective 30% interest in a refinery at Milford Haven, Wales that can process 108,000 barrels of crude oil a day. Refinery capacities at December 31, 1998, are shown in the following table. 3

MILFORD HAVEN, MERAUX, SUPERIOR, WALES LOUISIANA WISCONSIN (MURCO'S 30%) TOTAL --------- --------- -------------- ----- Crude capacity - b/sd* 100,000 35,000 32,400 167,400 Process capacity - b/sd* Vacuum distillation 50,000 20,500 16,500 87,000 Catalytic cracking - fresh feed 38,000 11,000 9,960 58,960 Pretreating cat-reforming feeds 22,000 9,000 5,490 36,490 Catalytic reforming 18,000 8,000 5,490 31,490 Distillate hydrotreating 15,000 7,800 20,250 43,050 Gas oil hydrotreating 27,500 -- -- 27,500 Solvent deasphalting 18,000 -- -- 18,000 Isomerization -- 2,000 2,250 4,250 Production capacity - b/sd* Alkylation 8,500 1,500 1,680 11,680 Asphalt -- 7,500 -- 7,500 Crude oil and product storage capacity - barrels 4,453,000 2,852,000 2,638,000 9,943,000 *Barrels per stream day. Murphy distributes refined products from 59 terminal locations in the United States to retail and wholesale accounts in the United States (by MOUSA) and in Canada (by a MOCL subsidiary) under the brand names SPUR(R) and Murphy USA(R) and to unbranded wholesale accounts. Eleven of these terminals are wholly owned and operated by MOUSA, 16 are jointly owned and operated by others, and the remaining 32 are owned by others. Of the terminals wholly owned or jointly owned, four are supplied by marine transportation, three are supplied by truck, two are adjacent to MOUSA's refineries, and 18 are supplied by pipeline. MOUSA receives products at the terminals owned by others in exchange for deliveries from the Company's wholly owned and jointly owned terminals. At the end of 1998, refined products were marketed at wholesale or retail through 552 branded stations in 17 states in the Southeast and Upper Midwest and eight branded stations in the Thunder Bay area of Ontario, Canada. At the end of 1998, Murco distributed refined products in the United Kingdom from the Milford Haven refinery, three wholly owned terminals supplied by rail, seven terminals owned by others where products are received in exchange for deliveries from the Company's wholly owned terminals, and 389 branded stations under the brand names MURCO and EP. Murphy owns a 20% interest in a 120-mile refined products pipeline, with a capacity of 165,000 barrels a day, that transports products from the Meraux refinery to two common carrier pipelines serving Murphy's marketing area in the southeastern United States. The Company also owns a 22% interest in a 312-mile crude oil pipeline in Montana and Wyoming, with a capacity of 120,000 barrels a day, and a 3.2% interest in LOOP Inc., which provides deepwater unloading accommodations off the Louisiana coast for oil tankers and onshore facilities for storage of crude oil. In addition, Murphy owns 29.4% of a 22-mile crude oil pipeline, with a capacity of 300,000 barrels a day, that connects LOOP storage at Clovelly, Louisiana and Alliance, Louisiana and 100% of a 24-mile crude oil pipeline, with a capacity of 200,000 barrels a day, that connects Alliance to the Meraux refinery. The pipeline from Alliance to Meraux is also connected to another company's pipeline system, allowing crude oil transported by that system to be shipped to the Meraux refinery. 4

At December 31, 1998, MOCL operated the following Canadian crude oil pipelines, with the ownership percentage, extent and capacity in barrels a day of each as shown. MOCL also operated and owned all or most of several short lateral connecting pipelines. PIPELINE DESCRIPTION PERCENT MILES BBLS./DAY ROUTE - - -------- ----------- ------- ----- --------- ----- Manito Dual heavy oil 52.5 101 65,000 Dulwich to Kerrobert, Sask. North-Sask Dual heavy oil 36.1 40 20,000 Paradise Hill to Dulwich, Sask. Cactus Lake Dual heavy oil 13.1 40 50,000 Cactus Lake to Kerrobert, Sask. Bodo Dual heavy oil 41.3 15 18,000 Bodo, Alta. to Cactus Lake, Sask. Milk River Dual medium/light oil 100 10.5 118,000 Milk River, Alta. to U.S. border Wascana Single light oil (idle) 100 108 45,000 Regina, Sask. to U.S. border Senlac Dual heavy oil 100 28 15,000 Senlac to Unity, Sask. Additional information about current refining, marketing and transportation activities and a statistical summary of key operating and financial indicators for each of the five years ended December 31, 1998, are reported on pages 2, 3, 5, 16 through 19, and 22 of the 1998 Annual Report. EMPLOYEES Murphy had 1,566 full-time and part-time employees at December 31, 1998. COMPETITION AND OTHER CONDITIONS WHICH MAY AFFECT BUSINESS Murphy operates in the oil industry and experiences intense competition from other oil and gas companies, many of which have substantially greater resources. 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 occasionally purchases refined products and may therefore 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" on page 18 of this Form 10-K report. 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" on page 15 of this Form 10-K report), preferential and discriminatory awarding of oil and gas leases, restraints and controls on imports and exports, safety, and relationships between employers and employees. Because these and other factors too numerous to list are subject to constant changes dictated by governmental and political considerations and are often made in great haste in response to changing internal and worldwide economic conditions and to actions of other governments or specific events, it is not practical to attempt to predict the effects of such factors on Murphy's future operations and earnings. Murphy's policy is to insure against known risks when insurance is available at costs and terms Murphy considers reasonable. Certain existing risks are insured by Murphy only through Oil Insurance Limited (OIL), which is operated as a mutual insurance company by certain participating oil companies including Murphy. OIL was organized to insure against risks for which commercial insurance is unavailable or for which the cost of commercial insurance is prohibitive. 5

EXECUTIVE OFFICERS OF THE REGISTRANT The age at January 1, 1999, 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. R. Madison Murphy - Age 41; Chairman of the Board since October 1994. Mr. Murphy had been Executive Vice President and Chief Financial and Administrative Officer, Director and Member of the Executive Committee since 1993. Prior to that, he was Executive Vice President and Chief Financial Officer from 1992 to 1993; Vice President, Planning/Treasury, from 1991 to 1992; and Vice President, Planning, from 1988 to 1991, with additional duties as Treasurer from 1990 until August 1991. Claiborne P. Deming - Age 44; President and Chief Executive Officer since October 1994 and Director and Member of the Executive Committee since 1993. In 1992, he became Executive Vice President and Chief Operating Officer. Mr. Deming was President of MOUSA from 1989 to 1992. Steven A. Cosse' - Age 51; Senior Vice President since October 1994 and General Counsel since August 1991. Mr. Cosse' was elected Vice President in 1993. For the eight years prior to August 1991, he was General Counsel for Murphy Expro, at that time named Ocean Drilling & Exploration Company (ODECO), a majority-owned subsidiary of Murphy. Herbert A. Fox Jr. - Age 64; Vice President since October 1994. Mr. Fox has also been President of MOUSA since 1992. He served with MOUSA as Vice President, Manufacturing, from 1990 to 1992. Bill H. Stobaugh - Age 47; Vice President since May 1995, when he joined the Company. Prior to that, he had held various engineering, planning and managerial positions, most recently with an engineering consulting firm. Odie F. Vaughan - Age 62; Treasurer since August 1991. From 1975 through July 1991, he was with ODECO as Vice President of Taxes and Treasurer. Ronald W. Herman - Age 61; Controller since August 1991. He was Controller of ODECO from 1977 through July 1991. Walter K. Compton - Age 36; Secretary since December 1996. He has been an attorney with the Company since 1988 and became Manager, Law Department, in November 1996. ITEM 3. LEGAL PROCEEDINGS Following a 1998 compliance inspection of the Superior, Wisconsin refinery, the Company received from the U.S. Environmental Protection Agency notices of violations of the Clean Air Act. Although the penalty amounts were not listed, the statutes involved provide for rates up to $27,500 per day of violation, and penalties therefore could exceed $100,000. The Company believes it has valid defenses to the alleged violations and plans a vigorous defense. While the notices of violation are preliminary in nature and no assurances can be given, the Company does not believe that the ultimate resolution of the matter will have a material adverse effect on the financial condition of the Company. Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business and none of which is expected to have a material adverse effect on the Company's financial condition. 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 1998. 6

PART II Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The Company's Common Stock is listed on the New York Stock Exchange and The Toronto Stock Exchange using "MUR" as the trading symbol. There were 3,684 stockholders of record as of December 31, 1998. Information as to high and low market prices per share and dividends per share by quarter for 1998 and 1997 are reported on page F-28 of this Form 10-K report. Item 6. SELECTED FINANCIAL DATA (THOUSANDS OF DOLLARS EXCEPT PER SHARE DATA) 1998 1997 1996 1995 1994 ---- ---- ---- ---- ---- RESULTS OF OPERATIONS FOR THE YEAR/1/ Sales and other operating revenues/2/ $1,694,470 2,133,387 2,009,736 1,613,848 1,582,091 Net cash provided by continuing operations 321,091 401,843 472,480 309,878 312,251 Income (loss) from continuing operations (14,394) 132,406 125,956 (127,919) 89,347 Net income (loss) (14,394) 132,406 137,855 (118,612) 106,628 Per Common share - diluted Income (loss) from continuing operations (.32) 2.94 2.80 (2.85) 1.99 Net income (loss) (.32) 2.94 3.07 (2.65) 2.38 Cash dividends per Common share 1.40 1.35 1.30 1.30 1.30 Percentage return on Average stockholders' equity (1.3) 12.7 12.2 (9.3) 8.6 Average borrowed and invested capital (.6) 10.4 10.4 (7.9) 8.0 Average total assets (.6) 6.0 6.2 (5.2) 4.8 CAPITAL EXPENDITURES FOR THE YEAR Exploration and production $ 331,647 423,181 373,984 231,718 286,348 Refining, marketing and transportation 55,025 37,483 42,880 53,602 94,697 Corporate and other 2,127 7,367 1,192 1,831 4,876 ---------- --------- --------- --------- --------- $ 388,799 468,031 418,056 287,151 385,921 ========== ========= ========= ========= ========= FINANCIAL CONDITION AT DECEMBER 31 Current ratio 1.15 1.10 1.10 1.22 1.14 Working capital $ 56,616 48,333 56,128 87,388 61,750 Net property, plant and equipment 1,662,362 1,655,838 1,556,830 1,377,455 1,558,716 Total assets 2,164,419 2,238,319 2,243,786 2,098,466 2,297,459 Long-term debt 333,473 205,853 201,828 193,146 172,289 Stockholders' equity 978,233 1,079,351 1,027,478/3/ 1,101,145 1,270,679 Per share 21.76 24.04 22.90 24.56 28.34 Long-term debt - percent of capital employed 25.4 16.0 16.4 14.9 11.9 /1/Includes effects on income of special items in 1998, 1997 and 1996 that are detailed in Management's Discussion and Analysis of Financial Condition and Results of Operations. Also, special items in 1995 and 1994 increased (decreased) net income by $(152,066), $(3.39) a diluted share, and $20,236, $.45 a diluted share, respectively. /2/Amounts prior to 1998 have been restated to conform to 1998 presentation. /3/Reflects $172,561 charge for distribution of common stock of Deltic Timber Corporation to stockholders. 7

Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS The Company reported a net loss in 1998 of $14.4 million, $.32 a diluted share, compared to net income in 1997 of $132.4 million, $2.94 a diluted share. In 1996, the Company earned $137.9 million, $3.07 a diluted share. Results of operations for the three years ended December 31, 1998, included certain special items that resulted in a net charge of $57.9 million, $1.29 a diluted share, in 1998; a net benefit of $.1 million, with no per share effect, in 1997; and a net benefit of $22.2 million, $.49 a diluted share, in 1996. The 1998 special items included an after-tax charge of $57.6 million, $1.28 a diluted share, from a write-down of assets determined to be impaired under Statement of Financial Accounting Standards (SFAS) No. 121. Net income for 1996 included earnings from discontinued operations of $11.9 million, $.27 a diluted share. This amount was attributable to the activities of the Company's farm, timber and real estate subsidiary, which was spun off to the Company's shareholders on December 31, 1996, as described in Note B to the consolidated financial statements. 1998 vs. 1997 - Excluding special items, income from continuing operations totaled $43.5 million in 1998, $.97 a diluted share, a decrease of $88.8 million from the $132.3 million earned in 1997. The income reduction was primarily attributable to a $79.2 million decline in earnings from the Company's exploration and production operations. Sharply lower crude oil prices in 1998 were the main reason for the reduction. The Company's average crude oil sales price declined by $5.62 a barrel in 1998, down 34% from oil prices realized in 1997. Higher crude oil production from new fields in Canada and the United Kingdom were mostly offset by lower production from maturing U.S. and U.K. oil fields and by selective shut-in of Canadian heavy oil production. Natural gas sales prices in the United States declined 15% in 1998 and U.S. natural gas production was down 20%. Earnings from the Company's refining, marketing and transportation operations were down $7.5 million in 1998, as record levels of finished product sales volumes were more than offset by lower unit margins on product sales in the United States. The costs of corporate activities, which includes interest income and expense and corporate overhead not allocated to operating functions, increased $2.1 million in 1998 compared to 1997, primarily due to higher net interest costs offset in part by lower costs of awards under the Company's incentive plans. 1997 vs. 1996 - Excluding special items, income from continuing operations in 1997 totaled $132.3 million, $2.94 a diluted share. The results for 1997 represented a $28.5 million improvement compared to income from continuing operations of $103.8 million, $2.31 a diluted share, in 1996. Earnings from the Company's exploration and production operations declined $16.8 million in 1997, primarily due to higher exploration costs. Increases in crude oil production and natural gas sales led to record hydrocarbon production in 1997 of 102,272 barrels a day on an energy equivalent basis. However, lower worldwide crude oil sales prices nearly offset the benefit of higher production volumes. Income from the Company's refining, marketing and transportation segment was up $42.6 million in 1997. The improvement occurred primarily in the United States, where the effects of lower costs for crude oil and other feedstocks exceeded the decline in sales realizations for the Company's finished products. An improved onstream rate helped the Company's U.S. refineries achieve a record level of crude oil throughputs in 1997. Sales of finished products in the United States were also higher during 1997. The cost of corporate activities decreased $2.7 million in 1997 compared to 1996, primarily due to lower costs of awards under the Company's incentive plans. In the following table, the Company's results of operations for the three years ended December 31, 1998, are presented by segment. Special items, which can obscure underlying trends of operating results and affect comparability between years, are set out separately. More detailed reviews of operating results for the Company's exploration and production and refining, marketing and transportation activities follow the table. 8

(MILLIONS OF DOLLARS) 1998 1997 1996 ---- ---- ---- Exploration and production United States $ 20.1 56.5 50.4 Canada 2.6 18.8 27.6 United Kingdom .7 13.1 14.7 Ecuador 2.4 12.9 13.8 Other (20.0) (16.3) (4.7) -------- ------ ----- 5.8 85.0 101.8 -------- ------ ----- Refining, marketing and transportation United States 27.7 41.3 1.8 United Kingdom 16.8 9.2 6.2 Canada 4.7 6.2 6.1 -------- ------ ------ 49.2 56.7 14.1 -------- ------ ------ Corporate (11.5) (9.4) (12.1) Income from continuing operations before -------- ------ ------ special items 43.5 132.3 103.8 Impairment of long-lived assets (57.6) (16.2) -- Charge resulting from cancellation of a drilling rig contract (4.2) -- -- Write-down of crude oil inventories to market value (4.2) -- -- Modification of U.K. long-term sales contract 2.8 -- -- Gain on sale of assets 2.9 11.5 17.7 Net recovery (loss) pertaining to 1996 modifications of foreign crude oil contracts 2.4 1.6 (.6) Refund and settlement of income tax matters -- 3.2 5.1 ------- ----- ----- Income (loss) from continuing operations (14.4) 132.4 126.0 Income from discontinued operations -- -- 11.9 ------- ----- ----- Net income (loss) $ (14.4) 132.4 137.9 ======= ===== ===== EXPLORATION AND PRODUCTION - Earnings from exploration and production operations before special items were $5.8 million in 1998, $85 million in 1997 and $101.8 million in 1996. The decline in 1998 was primarily due to lower worldwide crude oil sales prices, which averaged $10.81 a barrel in 1998 compared to $16.43 in 1997. Lower U.S. natural gas sales prices and volumes also contributed to the decline. Partial offsets were provided by higher crude oil production and lower exploration costs. Crude oil production from new fields in the United Kingdom brought on stream during the third quarter of 1998 and from the Hibernia field, offshore Newfoundland, which came on stream in late 1997, were partially offset by selective shut-in of heavy oil production in western Canada in response to lower heavy oil prices and by lower production from mature oil fields in the United States and the United Kingdom. In 1997, a $24.6 million increase in exploration costs, primarily in the U.S. Gulf of Mexico and Bohai Bay, China, accounted for the decline in earnings. While crude oil production increased 8% and natural gas sales increased 22% in 1997, these favorable production volumes were mostly offset by a 13% decline in the average worldwide crude oil sales price. The results of operations for oil and gas producing activities for each of the last three years are shown by major operating area on pages F-25 and F-26 of this Form 10-K report. Daily production rates and weighted average sales prices are shown on page 21 of the 1998 Annual Report. A summary of oil and gas revenues, including intersegment sales that are eliminated in the consolidated financial statements, is presented in the following table. 9

(MILLIONS OF DOLLARS) 1998 1997 1996 ---- ---- ---- United States Crude oil $ 35.6 74.9 86.1 Natural gas 132.1 196.7 147.1 Canada Crude oil 55.4 71.6 81.6 Natural gas 24.0 22.1 17.3 Synthetic oil 53.0 67.9 63.3 United Kingdom Crude oil 70.3 95.3 102.1 Natural gas 10.0 12.2 14.4 Ecuador - crude oil 19.1 34.7 35.0 Spain - natural gas - - 7.8 ------ ----- ----- Total oil and gas revenues $399.5 575.4 554.7 ====== ===== ===== The Company's crude oil and gas liquids production averaged 59,128 barrels a day in 1998, 57,494 in 1997 and 53,210 in 1996. Crude oil and liquids production in the United States declined 28% in 1998, with the reduction primarily due to declining production at mature oil fields in the Gulf of Mexico. In 1997, U.S. production was down 8% from 1996, primarily due to the sale of onshore producing properties effective July 1, 1996. For the second straight year, production in Canada rose 12%, and in 1998 established a record of 28,199 barrels a day. As a result of the selective shut-in, production of heavy oil in Canada decreased 16% in 1998 compared to a 19% increase in 1997. The Company's net interest in production of synthetic oil in Canada increased 12% in 1998, after a 14% increase in 1997. The increase in net synthetic oil production in 1998 was due to a 1% increase in gross production and a decrease in the net profits royalty rate as a result of lower oil prices. The increase in net production in 1997 was due to a 3% increase in gross production and a decrease in the net profits royalty rate. Before royalties, the Company's synthetic oil production was 10,501 barrels a day in 1998, 10,371 in 1997 and 10,036 in 1996. The Company's Hibernia field, on stream for all of 1998, produced 4,192 barrels a day in 1998 compared to 224 in 1997 after production commenced in the fourth quarter. The Company's U.K. oil production increased 11% in 1998 after a 5% increase in 1997. Oil production from the Mungo/Monan and Schiehallion fields commenced in the third quarter of 1998 and averaged 2,025 and 1,219 barrels a day, respectively. Production from the "T" Block field in the United Kingdom declined by 18% during 1998. A full year of production from the Thelma field contributed to an 11% increase in "T" Block production in 1997. Production from Ninian, the Company's other major North Sea oil field, declined 8% in 1998 after having declined 3% in 1997. Production in Ecuador was essentially unchanged in 1998 after a 30% increase in 1997. The 1997 increase resulted from new fields being placed on stream throughout 1996. Worldwide sales of natural gas averaged 230.9 million cubic feet a day in 1998, 268.7 million in 1997 and 220.6 million in 1996. A 20% decline in U.S. natural gas sales in 1998 was mainly due to reduced deliverability in certain of the Company's maturing Gulf of Mexico fields. Sales of natural gas in the United States increased 36% in 1997 as a number of new fields came on stream in the Gulf of Mexico. Natural gas sales in Canada in 1998 were at record levels for the third straight year, as sales increased 9% in 1998 following a 4% increase in 1997. Natural gas sales in the United Kingdom were down 2% in 1998, compared to a 17% decrease in 1997. Production of natural gas in Spain ceased at the end of 1996. As previously indicated, worldwide crude oil sales prices weakened considerably throughout 1998. The declining 1998 sales prices followed a previous softening of prices in 1997 as compared to 1996 prices. In the United States, Murphy's 1998 average monthly sales prices for crude oil and condensate ranged from $9.65 to $15.66 a barrel, and averaged $12.76 for the year, 34% below the average 1997 price. In Canada, the average sales price for light oil was $12.03 a barrel in 1998, a decline of 32%. Heavy oil prices in Canada averaged $6.56 a barrel, down 39% from 1997. The average sales price for synthetic oil in 1998 was $13.73 a barrel, off 31% from a year earlier. The sales price for crude oil from the Hibernia field averaged $10.49 a barrel, down 31%. Sales prices in the United Kingdom were down 34% in 1998 and averaged $12.52 a barrel. Sales prices in Ecuador averaged $6.76 a barrel in 1998, down 44% compared to a year ago. U.S. oil prices decreased 4% in 1997 compared to 1996 and averaged $19.43 a barrel for the year. In Canada, crude oil prices in 1997 declined 11% for light oil, 25% for heavy oil and 6% for synthetic oil. Sales prices in the United Kingdom were down 10% in 1997 and prices in Ecuador were down 24%. Worldwide crude oil prices began to decline in the fourth quarter of 1997, and the downward trend continued throughout 1998. Oil prices remain under extreme pressure in early 1999. 10

Average monthly natural gas sales prices in the United States ranged from $1.73 to $2.51 an MCF during 1998. For the year, U.S. sales prices averaged $2.18 an MCF compared to $2.57 a year ago. The average price for natural gas sold in Canada during 1998 was $1.34 an MCF, essentially unchanged from the prior year, while prices in the United Kingdom declined 16% to $2.23. The decline in average U.K. sales prices primarily resulted from a modification of a long-term sales contract effective October 1, 1998. Average U.S. natural gas sales prices in 1997 were essentially unchanged compared to 1996; prices were up in Canada and the United Kingdom by 23% and 3%, respectively, during the same period. U.S. natural gas sales prices have declined sharply in early 1999. Based on 1998 volumes and deducting taxes at marginal rates, each $1 a barrel and $.10 an MCF fluctuation in prices would have affected annual exploration and production earnings by $14.4 million and $5.3 million, respectively. The effect of these price fluctuations on consolidated net income cannot be measured because operating results of the Company's refining, marketing and transportation segments could be affected differently. Production costs were $155.1 million in 1998, $164.8 million in 1997 and $160.5 million in 1996. These amounts are shown by major operating area on pages F-25 and F-26 of this Form 10-K report. Costs per equivalent barrel of production during the last three years were as follows. (DOLLARS PER EQUIVALENT BARREL) 1998 1997 1996 ---- ---- ---- United States $ 3.32 2.59 3.31 Canada Excluding synthetic oil 3.64 4.63 3.95 Synthetic oil 8.99 11.32 12.72 United Kingdom 5.60 5.58 6.00 Ecuador 2.48 3.87 4.96 Worldwide - excluding synthetic oil 3.79 3.72 4.09 The increase in U.S. production cost per equivalent barrel in 1998 was attributable to lower production volumes combined with higher workover costs. The decline in Canada in 1998, excluding synthetic oil, was caused by higher oil production at Hibernia, voluntary shut-in of certain high-cost heavy oil production and a lower Canadian dollar exchange rate vs. the U.S. dollar. The decrease in the Canadian synthetic oil unit rate was due to lower maintenance costs, a decrease in royalty barrels due to a lower sales price and a lower Canadian dollar exchange rate. The lower cost in Ecuador in 1998 was caused by lower energy and other field operating costs during the year. The decrease in the U.S. cost per equivalent barrel in 1997 was attributable to the sale of high-cost onshore producing properties in 1996. The 1997 increase in Canada, excluding synthetic oil, was due to an increase in heavy oil production compared to light oil and to higher costs associated with an expansion of heavy oil thermal recovery projects. The decrease in the cost for synthetic oil in 1997 was due to higher gross production volumes and a decrease in royalty barrels caused by lower sales prices. Based on synthetic oil production before royalties, costs per barrel declined 2% in 1997. A lower unit cost in the United Kingdom in 1997 was due to a favorable impact from higher production at "T" Block. 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-25 and F-26 of this Form 10-K report. Certain of the expenses are included in the capital expenditure totals for exploration and production activities. (MILLIONS OF DOLLARS) 1998 1997 1996 ---- ---- ---- Included in capital expenditures Dry hole costs $ 31.5 48.3 28.5 Geological and geophysical costs 17.0 26.4 24.1 Other costs 6.6 9.6 7.9 ------ ---- ---- 55.1 84.3 60.5 Undeveloped lease amortization 10.5 10.5 9.7 ------ ---- ---- Total exploration expenses $ 65.6 94.8 70.2 ====== ==== ==== Depreciation, depletion and amortization for exploration and production operations totaled $163.1 million in 1998, $172.4 million in 1997 and $147.6 million in 1996. The decrease in 1998 was primarily attributable to lower worldwide hydrocarbon production, while the increase in 1997 was mainly due to higher worldwide production. 11

REFINING, MARKETING AND TRANSPORTATION - Earnings from refining, marketing and transportation operations before special items were $49.2 million in 1998, $56.7 million in 1997 and $14.1 million in 1996. Operations in the United States earned $27.7 million in 1998 compared to $41.3 million in 1997, as average product sales realizations declined more than costs of crude oil and other refinery feedstocks. U.S. operations earned $1.8 million in 1996. Crude oil swap agreements increased earnings by $5 million in 1997 and $9.2 million in 1996. U.K. operations earned $16.8 million before special items in 1998, $9.2 million in 1997 and $6.2 million in 1996. The improvement in the United Kingdom in 1998 was caused by a larger decline for refining feedstock costs than for sales prices of finished products, coupled with higher finished product sales volumes. Canadian operations contributed $4.7 million to 1998 earnings compared to $6.2 million in 1997 and $6.1 million in 1996. Unit margins (sales realizations less costs of crude oil, other feedstocks, refining and transportation to point of sale) averaged $1.47 a barrel in the United States in 1998, $1.79 in 1997 and $.27 in 1996. U.S. product sales were up 3% in 1998 following a 5% increase in 1997. U.S. margins came under pressure during the second half of 1998, at which time unit margins retreated substantially. U.S. margins improved considerably in 1997 after being under pressure throughout 1996. Unit margins were very weak in early 1999 and the Company was experiencing losses in its U.S. downstream operations. Unit margins in the United Kingdom averaged $2.81 a barrel in 1998, $2.90 in 1997 and $2.08 in 1996. Sales of petroleum products were up 25% in 1998 following a 14% decline in 1997. Sales in both terminal and cargo markets increased in 1998. Cargo sales in 1997 were adversely affected by a turnaround at the Milford Haven refinery early in the year. Although margins remained relatively strong in 1998, the Company's branded outlets still face stiff competition from supermarket sales of motor fuels. Sharp declines in unit margins in the United Kingdom in early 1999 have led to losses in these operations. Based on sales volumes for 1998 and deducting taxes at marginal rates, each $.42 a barrel ($.01 a gallon) fluctuation in unit margins would have affected annual refining and marketing profits by $17 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. Income before special items from purchasing, transporting and reselling crude oil in Canada in 1998 was down $1.5 million as lower prices for heavy oil led to production shut-ins, which brought about lower pipeline throughputs and fewer barrels available for crude trading activities. Income in 1997 was virtually unchanged from 1996 as higher pipeline throughputs and better margins on crude oil trucking operations were offset by lower crude trading margins. SPECIAL ITEMS - Net income for the last three years included the special items reviewed below; the quarter in which each item occurred is indicated. The effects of special items on quarterly results for 1998 and 1997 are presented on page F-28 of this Form 10-K report. . Impairment of long-lived assets - An after-tax provision of $57.6 million was recorded in the fourth quarter of 1998 and after-tax provisions of $3.3 million and $12.9 million were recorded in the third and fourth quarters, respectively, of 1997 for the write-down of assets determined to be impaired (see Note C to the consolidated financial statements). . Charge resulting from cancellation of a drilling rig contract - An after-tax charge of $4.2 million was recorded in the fourth quarter of 1998 resulting from cancellation of a drilling rig contract for the Terra Nova oil field, offshore eastern Canada. The contract was cancelled because management believes that current market conditions will allow a more efficient and modern rig to be obtained, reducing drilling costs for the Terra Nova project compared to what they might otherwise have been. . Write-down of crude oil inventories to market value - An after-tax charge of $4.2 million was recorded in the fourth quarter of 1998 to establish a valuation allowance to reduce the carried amount of crude oil inventories in the United Kingdom and Canada to market values. . Modification of U.K. long-term sales contract - An after-tax gain of $2.8 million was recorded in the second quarter of 1998 related to a modification of a U.K. long-term sales contract. 12

. Gain on sale of assets - After-tax gains on sale of assets included $2.9 million recorded in the fourth quarter of 1998 from sale of a U.K. service station, $11.5 million recorded in the fourth quarter of 1997 from sale of a Canadian heavy oil property, and $17.7 million recorded in the third quarter of 1996 from sale of 48 onshore producing oil and gas properties in the United States. . Net recovery (loss) pertaining to 1996 modifications of foreign crude oil contracts - Gains of $1.4 million, $1 million and $1.6 million were recorded in the second quarter of 1998, the fourth quarter of 1998 and the fourth quarter of 1997, respectively, for partial recoveries of a 1996 loss resulting from modification to a crude oil production contract in Ecuador. A net loss of $.6 million was recorded in the fourth quarter of 1996 resulting from modifications to contracts related to crude oil production in Ecuador and Gabon (see Note N to the consolidated financial statements). . Refund and settlement of income tax matters - A gain of $3.2 million for refund of U.K. income taxes was recorded in the third quarter of 1997. A gain of $5.1 million for settlement of income tax matters in Canada was recorded in the fourth quarter of 1996. The income (loss) effects of special items for the three years ended December 31, 1998, are summarized by segment in the following table. (MILLIONS OF DOLLARS) 1998 1997 1996 ---- ---- ---- Exploration and production United States $ (19.4) (4.9) 17.7 Canada (10.1) .2 5.1 United Kingdom (14.0) 3.2 -- Ecuador 2.4 1.6 (8.8) Other (15.1) -- 8.2 ---- ---- ---- (56.2) .1 22.2 ---- ---- ---- Refining, marketing and transportation United Kingdom .5 -- -- Canada (2.2) -- -- ---- ---- ---- (1.7) -- -- ---- ---- ---- Total income (loss) from special items $ (57.9) .1 22.2 ==== ==== ==== CAPITAL EXPENDITURES As shown in the selected financial data on page 7 of this Form 10-K report, capital expenditures were $388.8 million in 1998 compared to $468 million in 1997 and $418.1 million in 1996. These amounts included $55.1 million, $84.3 million and $60.5 million of exploration expenditures that were expensed. Capital expenditures for exploration and production activities totaled $331.6 million in 1998, 85% of the Company's total capital expenditures for the year. Exploration and production capital expenditures in 1998 included $17 million for acquisition of undeveloped leases, $4.9 million for acquisition of proved oil and gas properties, $120.4 million for exploration activities and $189.3 million for development projects. Development expenditures included $11.2 million and $41.7 million for the Hibernia and Terra Nova oil fields, respectively, offshore Newfoundland; $27.1 million and $25.2 million for the Schiehallion and Mungo/Monan fields, respectively, offshore United Kingdom; and $10.2 million for oil fields in Ecuador. Exploration and production capital expenditures are shown by major operating area on page F-24 of this Form 10-K report. Amounts shown under "Other" included $9.5 million in 1998 from drilling two unsuccessful offshore wildcat wells in the Falkland Islands and $18.3 million in 1997 for exploration drilling and related costs in Bohai Bay, China. Refining, marketing and transportation expenditures, detailed in the following table, were $55 million in 1998, or 14% of total capital expenditures, compared to $37.5 million in 1997 and $42.9 million in 1996. 13

(MILLIONS OF DOLLARS) 1998 1997 1996 ---- ---- ---- Refining United States $ 27.0 12.5 13.2 United Kingdom .7 1.5 12.2 ------- ---- ---- Total refining 27.7 14.0 25.4 ------- ---- ---- Marketing United States 16.7 14.1 7.5 United Kingdom 6.1 2.2 1.3 ------- ---- ---- Total marketing 22.8 16.3 8.8 ------- ---- ---- Transportation United States 1.9 2.6 .3 Canada 2.6 4.6 8.4 ------- ---- ---- Total transportation 4.5 7.2 8.7 ------- ---- ---- Total $ 55.0 37.5 42.9 ======= ==== ==== U.S. refining expenditures were primarily for capital projects to keep the refineries operating efficiently and within industry standards and to study alternatives for meeting anticipated future environmentally driven changes to motor fuel specifications. Marketing expenditures included the costs of new stations, primarily on land leased in the United States from Wal-Mart Stores, and improvements and normal replacements at existing stations and terminals. CASH FLOWS Cash provided by continuing operations was $321.1 million in 1998, $401.8 million in 1997 and $472.5 million in 1996. Special items reduced cash flow from operations by $6.3 million in 1998 and $12.8 million in 1996, but increased cash by $3.8 million in 1997. Changes in operating working capital other than cash and cash equivalents required cash of $3.8 million and $72.4 million in 1998 and 1997, respectively, but provided cash of $77.1 million in 1996. Cash provided by continuing operations was further reduced by expenditures for refinery turnarounds and abandonment of oil and gas properties totaling $24.6 million in 1998, $14.4 million in 1997 and $10.8 million in 1996. Cash proceeds from property sales were $9.5 million in 1998, $43.8 million in 1997 and $55.5 million in 1996. Borrowings under long-term notes payable provided $161.3 million of cash in 1998 and $9.7 million in 1997. Additional borrowings under nonrecourse debt arrangements provided $6.4 million of cash in 1997 and $23.1 million in 1996. Capital expenditures required $388.8 million of cash in 1998, $468 million in 1997 and $418.1 million in 1996. Other significant cash outlays during the three years included $34.5 million in 1998, $17.3 million in 1997 and $11.4 million in 1996 for debt repayment. Cash used for dividends to stockholders was $62.9 million in 1998, $60.6 million in 1997 and $58.3 million in 1996. FINANCIAL CONDITION Year-end working capital totaled $56.6 million in 1998, $48.3 million in 1997 and $56.1 million in 1996. The current level of working capital does not fully reflect the Company's liquidity position, as the carrying values assigned to inventories under LIFO accounting were $14.7 million below current costs at December 31, 1998. Cash and equivalents at the end of 1998 totaled $28.3 million compared to $24.3 million a year ago and $109.7 million at the end of 1996. Long-term debt increased $127.6 million during 1998 to $333.5 million at the end of the year, 25.4% of total capital employed, and included $143.8 million of nonrecourse debt incurred in connection with the acquisition and development of Hibernia. Long-term debt totaled $205.9 million at the end of 1997 compared to $201.8 million at December 31, 1996. Stockholders' equity was $1 billion at the end of 1998 compared to $1.1 billion a year ago and $1 billion at the end of 1996. A summary of transactions in the stockholders' equity accounts is presented on page F-5 of this Form 10-K report. The primary sources of the Company's liquidity are internally generated funds, access to outside financing and working capital. The Company relies on internally generated funds to finance the major portion of its capital and other 14

expenditures, but maintains lines of credit with banks and borrows as necessary to meet spending requirements. Current financing arrangements are set forth in Note D to the consolidated financial statements. The Company does not expect any problem in meeting future requirements for funds. The Company had commitments of $209 million for capital projects in progress at December 31, 1998, including $90 million related to one third of a multiyear contract for a semisubmersible drilling rig capable of drilling in 6,000 feet of water. Delivery of the rig is scheduled for 1999. ENVIRONMENTAL The Company's operations are subject to numerous laws and regulations intended to protect the environment and/or impose remedial obligations. 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 refineries, oil and gas fields, service stations, and terminals, for which known or potential obligations for environmental remediation exist. Under the Company's accounting policies, a liability for an environmental obligation 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 years after a liability is recognized. The Company's reserve for remedial obligations, which is included in "Deferred Credits and Other Liabilities" in the Consolidated Balance Sheets, contains certain amounts that are based on anticipated regulatory approval for proposed remediation of former refinery waste sites. If regulatory authorities require more costly alternatives than the proposed processes, future expenditures could exceed the amount reserved by up to an estimated $3 million. The Company has received notices from the U.S. Environmental Protection Agency that it is currently considered a Potentially Responsible Party (PRP) at three Superfund sites and has also been assigned responsibility by defendants at another Superfund site. The potential total cost to all parties to perform necessary remedial work at these sites may be substantial. Based on currently available information, the Company has reason to believe that it is a de minimus party as to ultimate responsibility at the four sites. The Company does not expect that its related remedial costs will be material to its financial condition or its results of operations, and it has not provided a reserve for remedial costs on Superfund sites. Additional information may become known in the future that would alter this assessment, including any requirement to bear a pro rata share of costs attributable to nonparticipating PRPs or indications of additional responsibility by the Company. Following a compliance inspection in 1998, Murphy's Superior, Wisconsin refinery received from the U.S. Environmental Protection Agency notices of violations of the Clean Air Act. Although the penalty amounts were not listed, the statutes involved provide for rates up to $27,500 per day of violation. The Company believes it has valid defenses to the allegations and plans a vigorous defense. The Company does not believe that this or other known environmental matters will have a material adverse effect on its financial condition. There is the possibility that additional expenditures could be required at currently unidentified sites, and new or revised regulatory requirements could necessitate additional expenditures at known sites. Such expenditures could materially affect the results of operations 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, 1998. The Company's refineries also incur costs to handle and dispose of hazardous wastes and other chemical substances on a recurring basis. These costs are generally expensed as incurred and amounted to $3.8 million in 1998. In addition to remediation and other recurring expenditures, Murphy commits a portion of its capital expenditure program for compliance with environmental laws and regulations. Such capital expenditures were approximately $26 million in 1998 and are expected to be $44 million in 1999. 15

YEAR 2000 ISSUES GENERAL - The Year 2000 issue affects all companies and relates to the possibility that computer programs and embedded computer chips may be unable to accurately process data with year dates of 2000 and beyond. Murphy is devoting significant internal and external resources to address Year 2000 compliance, and the Company's Year 2000 project (Project) is proceeding well. In 1993, Murphy began a worldwide business systems replacement project using systems primarily from J.D. Edwards & Company (Edwards) in the United States and the United Kingdom, PricewaterhouseCoopers LLP (PW*Sequel) in Canada, and for exploration and production operations, Applied Terravision Systems Inc. (Artesia) in the United States, and EFA Software Services Ltd. (PRISM) in Canada. Certain U.S. business software systems developed by the Company will not be replaced with compliant vendor systems by the Year 2000 and have been remedied to be Year 2000 compliant. Remaining hardware, software and facilities are expected to be made Year 2000 compliant through the Project. None of the Company's other information technology projects are expected to be significantly delayed due to the implementation of the Project. PROJECT - The Company has established an Enterprise Project Office (EPO) and has engaged KPMG LLP to assist with Project management. The Project is primarily being managed by major operating location. At each location, the Project is divided into three major components: Computer Hardware, Applications Software, and Process Control and Instrumentation (Embedded Technology). The Computer Hardware component consists of computing equipment and systems software other than Applications Software. Applications Software includes both internally developed and vendor software systems. Embedded Technology includes the hardware, software and associated embedded computer chips (other than computing equipment) that are used in facilities operated by the Company. The general phases common to all components are: (1) inventorying Year 2000 items; (2) assigning priorities to identified items; (3) assessing the Year 2000 compliance of identified items; (4) repairing or replacing material items that are determined not to be Year 2000 compliant; (5) evaluating and testing required material items; and (6) designing and implementing contingency and business continuation plans as necessary. Material items are those that the Company believes to have safety, environmental or property damage risks, or that may adversely affect the Company's ability to process and record revenues if not properly addressed. The inventorying and priority assessment phases of the Project were completed during 1998. The remaining four phases of the Project are in progress and are being performed primarily by employees of the Company, with assistance from vendors and independent contractors. A fourth major component of the Project, which involves the review of third party suppliers, customers and business partners (Third Parties), is being managed for all locations by the EPO. This includes the process of identifying and prioritizing critical Third Parties and communicating with them about their plans and progress in addressing the Year 2000 problem. Detailed evaluations of the most critical Third Parties began in the second quarter of 1998 and are scheduled for completion by June 30, 1999, with follow-up reviews scheduled for the remainder of 1999. The Company estimates that this component was on schedule at December 31, 1998. Based on the results of evaluations and other available information, contingency plans will be developed as necessary during 1999 to address any anticipated Year 2000 problems related to critical Third Parties. A Year 2000 compliant version of Edwards has been fully implemented in the United States and is approximately 60% complete in the United Kingdom. Implementation of Edwards is ongoing in the United Kingdom and final phases are expected to be completed in October 1999. A contingency plan will be prepared in early 1999 to address the possibility that the last phases of the U.K. implementation will not be achieved by the end of 1999. A Year 2000 compliant version of Artesia was implemented in the United States at the end of 1998 and testing was completed in January 1999. In Canada, the Company expects to upgrade and test a Year 2000 compliant version of PRISM during the first quarter of 1999, with a compliant version of PW*Sequel scheduled to be fully implemented in April 1999. Testing of U.S. offshore production platform systems is scheduled to be completed by the end of the first quarter of 1999. Exploration system upgrades were released by the vendor in early 1999 and will be installed and tested by the third quarter of 1999. Remedy of certain internally developed downstream accounting, customer invoicing and human resources systems in the United States had been completed at December 31, 1998. Upgrading and testing of virtually all significant U.S. refining and marketing systems is scheduled to be completed by April 30, 1999. The operator at the Company's jointly owned U.K. refinery is directing that location's Year 2000 action plan; Company employees are monitoring the operator's progress and believe the work is on schedule. Systems at U.K. marketing terminals are being upgraded to a Year 2000 compliant version; this work is scheduled to be completed by March 31, 1999. Supply and transportation systems in Canada are expected to be essentially compliant by March 31, 1999. 16

PROJECT SUMMARY - At January 31, 1999, the overall Project is estimated to be 70% complete. Thus far, no material noncompliant Year 2000 issues have been discovered that were not identified in the completed Year 2000 inventory. The material components of the Project, except for the final stages of the Edwards implementation in the United Kingdom, are expected to be nearly complete by June 30, 1999. The Company does not expect to develop formal contingency plans for Project issues that are resolved in accordance with the current schedule. Any unresolved issues that fall significantly behind schedule or that lead to a material risk of system failure will be addressed by contingency plans during 1999. COSTS - The Company's total cost to become Year 2000 compliant is not expected to be material to its financial position. The most likely estimate of the total cost of the Project is approximately $5 million, of which $2 million is for the EPO (including assessment of Third Parties), $1 million is for miscellaneous hardware replacement, $1 million is for noncompliant system renovations and upgrades and $.6 million is for Embedded Technology issues. It is reasonably possible that total costs could exceed the most likely estimate by up to $1 million. Funds for the Project are primarily obtained from internally generated cash flows. This estimate does not include the Company's potential share of Year 2000 costs that may be incurred by partnerships and joint ventures that the Company does not operate, except for an estimated $.5 million to make Murphy's jointly owned U.K. refinery Year 2000 compliant. The cost of implementing Edwards in the United Kingdom, estimated to be $.9 million, is also not included in the Project cost estimate. The total amount expended on the Project through December 31, 1998, and recorded in selling and general expense in 1998 was $1.6 million, most of which related to the EPO. The remaining cost to complete the Year 2000 Project is estimated to be approximately $3.4 million. RISKS - Not correcting material Year 2000 problems could result in interruptions in, or failures of, certain normal business activities or operations. Such failures could materially and adversely affect the Company's results of operations, liquidity or financial condition by impeding the Company's ability to produce and deliver crude oil, natural gas and finished petroleum products, and to invoice and collect related revenues from customers. Due to the general uncertainty inherent in the Year 2000 problem, resulting in part from uncertainty about the Year 2000 readiness of critical Third Parties, the Company is unable to determine at this time whether or not the consequences of possible Year 2000 failures will materially affect its results of operations, liquidity or financial condition. The Project is expected to significantly reduce the Company's level of uncertainty about the Year 2000 issue, and in particular, about the Year 2000 compliance and readiness of the Company's critical Third Parties. The Company believes that it is taking reasonable steps to address potentially material Year 2000 failures, and with completion of the Project as scheduled, the possibility of significant interruptions of normal operations should be greatly reduced. Readers are cautioned that forward-looking statements contained in this Year 2000 section should be read in conjunction with Murphy's disclosures under the heading "Forward-Looking Statements" on page 18 of this Form 10-K report. 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 is impacted by the weather, and by the fact that delivery of supplies is generally restricted to specific geographic areas. Relatively high crude oil and natural gas prices led to upward pressure on amounts paid by the Company for goods and services during 1996 and 1997. Conversely, lower commodity prices in 1998 have caused a softening of prices for goods and services in recent months. 17

ACCOUNTING MATTERS - The Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," in June 1997. This statement establishes accounting and reporting standards for derivative instruments and hedging activities. Effective January 1, 2000, Murphy must recognize the fair value of all derivative instruments as either assets or liabilities in its Consolidated Balance Sheet. A derivative instrument meeting certain conditions may be designated as a hedge of a specific exposure; accounting for changes in a derivative's fair value will depend on the intended use of the derivative and the resulting designation. Any transition adjustments resulting from adopting this statement will be reported in net income or other comprehensive income, as appropriate, as the cumulative effect of a change in accounting principle. As described under the heading "Quantitative and Qualitative Disclosures About Market Risk" on page 19 of this Form 10-K report, the Company makes limited use of derivative instruments to hedge specific market risks. The Company has not yet determined the effects that SFAS No. 133 will have on its future consolidated financial statements or the amount of the cumulative adjustment that will be made upon adopting this new standard. OUTLOOK Planning for 1999 is difficult because prices for the Company's products remain uncertain. Worldwide crude oil sales prices remain under extreme pressure in early 1999, primarily caused by soft worldwide crude oil demand due to the weak Asian economy. In addition, relatively mild winter weather has led to significantly lower U.S. natural gas sales prices in early 1999. The low oil and natural gas sales prices, coupled with weak refining and marketing margins, continue to exert downward pressure on the Company's operating results in early 1999. The Company was experiencing losses in exploration and production and refining, marketing and transportation operations in early 1999. In such an environment, constant reassessment of spending plans is required. The Company's capital expenditure budget for 1999 was prepared during the fall of 1998, but spending plans have subsequently been revised downward to reflect the effects of the sharp decline in commodity prices seen in late 1998 and early 1999. The Company's present plans call for capital expenditures of $400 million in 1999, of which $290 million or 72% is allocated for exploration and production activities. Geographically, about 33% of the planned exploration and production spending is designated for the United States; 45% for Canada, including $75 million for further development of the Terra Nova oil field and $19 million at Syncrude, primarily for expansion of the Aurora mine; 16% for the United Kingdom, including $27 million for further development costs related to the Schiehallion and Mungo/Monan oil fields; 4% for continuing development of oil fields in Ecuador; and the remaining 2% for other overseas operations. Planned refining, marketing and transportation capital expenditures for 1999 are $110 million, including $95 million in the United States, $14 million in the United Kingdom and $1 million in Canada. U.S. amounts include funds for additional stations at Wal-Mart sites. Capital and other expenditures are under constant review and planned capital expenditures may be adjusted further to reflect changes in estimated cash flow as 1999 progresses. FORWARD-LOOKING STATEMENTS This Form 10-K report, including documents incorporated by reference herein, 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 on file with the U.S. Securities and Exchange Commission. 18

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company is exposed to market risks associated with interest rates, foreign currency exchange rates, and prices of crude oil, natural gas and petroleum products. Murphy makes limited use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions. All derivatives used for risk management are covered by operating policies and are closely monitored by the Company's senior management. The Company does not hold derivatives for trading purposes and it does not use derivatives with leveraged or complex features. Derivative instruments are traded either with creditworthy major financial institutions or over national exchanges. At December 31, 1998, the Company was a party to interest rate swaps with notional amounts totaling $100 million that were designed to convert a similar amount of variable-rate debt to fixed rates. The swaps mature in 2002 and 2004. The swaps require the Company to pay an average interest rate of 6.46% over their composite lives, and at December 31, 1998, the interest rate to be received by the Company averaged 5.23%. The variable interest rate received by the Company under each swap contract is repriced quarterly. The Company considers these swaps to be a hedge against potentially higher future interest rates. As described in Note I to the consolidated financial statements, the estimated fair value of these interest rate swaps was a negative $5.5 million at December 31, 1998. At December 31, 1998, 84% of the Company's long-term debt had variable interest rates and 45% was denominated in Canadian dollars. Certain debt with fixed interest rates at the end of 1998 is expected to be refinanced through variable-rate borrowings during 1999. Based on debt outstanding at December 31, 1998, a 10% increase in variable interest rates would increase the Company's interest expense in 1999 by $1.1 million, net of a $.5 million favorable effect resulting from lower net settlement payments under the aforementioned interest rate swaps. A 10% increase in the exchange rate of the Canadian dollar vs. the U.S. dollar would increase 1999 interest expense by $.3 million on debt denominated in Canadian dollars. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Information required by this item appears on pages F-1 through F-28 of this Form 10-K report. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None 19

PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Certain information regarding executive officers of the Company is included on page 6 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 12, 1999, under the caption "Election of Directors." ITEM 11. EXECUTIVE COMPENSATION Information required by this item is incorporated by reference to the Registrant's definitive Proxy Statement for the Annual Meeting of Stockholders on May 12, 1999, under the captions "Compensation of Directors," "Executive Compensation," "Option Exercises and Fiscal Year-End Values," "Option Grants," "Compensation Committee Report for 1998," "Shareholder Return Performance Presentation" and "Retirement Plans." ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Information required by this item is incorporated by reference to the Registrant's definitive Proxy Statement for the Annual Meeting of Stockholders on May 12, 1999, under the caption "Certain Stock Ownerships." ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Information required by this item is incorporated by reference to the Registrant's definitive Proxy Statement for the Annual Meeting of Stockholders on May 12, 1999, under the caption "Certain Relationships and Related Transactions." 20

PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (A) 1. FINANCIAL STATEMENTS The consolidated financial statements of Murphy Oil Corporation and consolidated subsidiaries are located or begin on the pages of this Form 10-K report as indicated below. Page No. -------- Report of Management F-1 Independent Auditors' Report F-1 Consolidated Statements of Income F-2 Consolidated Statements of Comprehensive Income F-2 Consolidated Balance Sheets F-3 Consolidated Statements of Cash Flows F-4 Consolidated Statements of Stockholders' Equity F-5 Notes to Consolidated Financial Statements F-6 Supplemental Oil and Gas Information (unaudited) F-22 Supplemental Quarterly Information (unaudited) F-28 2. FINANCIAL STATEMENT SCHEDULES Financial statement schedules are omitted because either they are not applicable or the required information is included in the consolidated financial statements or notes thereto. 3. EXHIBITS The following is an index of exhibits that are hereby filed as indicated by asterisk (*), are to be filed by an amendment as indicated by pound sign (#), or are incorporated by reference. Exhibits other than those listed have been omitted since they either are not required or are not applicable. EXHIBIT NO. INCORPORATED BY REFERENCE TO ------- ----------------------------------------- 3.1 Certificate of Incorporation of Murphy Oil Corporation as Exhibit 3.1 of Murphy's Form 10-K for the of September 25, 1986 year ended December 31, 1996 3.2 Bylaws of Murphy Oil Corporation at January 24, 1996 Exhibit 3.2 of Murphy's Form 10-K for the year ended December 31, 1997 4 Instruments Defining the Rights of Security Holders. Murphy is party to several long-term debt instruments in addition to the one in Exhibit 4.1, none of which authorizes securities exceeding 10% of the total consolidated assets of Murphy and its subsidiaries. Pursuant to Regulation S-K, item 601(b), paragraph 4(iii)(A), Murphy agrees to furnish a copy of each such instrument to the Securities and Exchange Commission upon request. 4.1 Credit Agreement among Murphy Oil Corporation and Exhibit 4.1 of Murphy's Form 10-K for the certain subsidiaries and the Chase Manhattan Bank year ended December 31, 1997 et al as of November 13, 1997 21

4.2 Rights Agreement dated as of December 6, 1989, Exhibit 4.1 of Murphy's Form 10-K for the year ended between Murphy Oil Corporation and Harris December 31, 1994 Trust Company of New York, as Rights Agent 4.3 Amendment No. 1 dated as of April 6, 1998, to Exhibit 3 of Murphy's Form 8-A/A, Amendment No. 1, filed Rights Agreement dated as of December 6, 1989, April 14, 1998, under the Securities Exchange Act of 1934 between Murphy Oil Corporation and Harris Trust Company of New York, as Rights Agent 10.1 1987 Management Incentive Plan as amended February Exhibit 10.2 of Murphy's Form 10-K for the year ended 7, 1990, retroactive to February 3, 1988 December 31, 1994 10.2 1992 Stock Incentive Plan as amended May 14, 1997 Exhibit 10.2 of Murphy's Form 10-Q for the quarterly period ended June 30, 1997 10.3 Employee Stock Purchase Plan Exhibit 99.01 of Murphy's Form S-8 Registration Statement filed May 19, 1997, under the Securities Act of 1933 * 13 1998 Annual Report to Security Holders including Narrative to Graphic and Image Material as an Appendix * 21 Subsidiaries of the Registrant * 23 Independent Auditors' Consent * 27 Financial Data Schedule for 1998 * 99.1 Undertakings # 99.2 Form 11-K, Annual Report for the fiscal year To be filed as an amendment to this Form 10-K not later ended December 31, 1998, covering the Thrift than 180 days after December 31, 1998 Plan for Employees of Murphy Oil Corporation # 99.3 Form 11-K, Annual Report for the fiscal year To be filed as an amendment to this Form 10-K not later ended December 31, 1998, covering the Thrift than 180 days after December 31, 1998 Plan for Employees of Murphy Oil USA, Inc. Represented by United Steelworkers of America, AFL-CIO, Local No. 8363 # 99.4 Form 11-K, Annual Report for the fiscal year To be filed as an amendment to this Form 10-K not later ended December 31, 1998, covering the Thrift than 180 days after December 31, 1998 Plan for Employees of Murphy Oil USA, Inc. Represented by International Union of Operating Engineers, AFL-CIO, Local No. 305 (b) Reports on Form 8-K No reports on Form 8-K were filed during the quarter ended December 31, 1998. 22

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. MURPHY OIL CORPORATION By CLAIBORNE P. DEMING Date: March 24, 1999 ------------------------------------ ---------------------- Claiborne P. Deming, President Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 24, 1999, by the following persons on behalf of the registrant and in the capacities indicated. R. MADISON MURPHY MICHAEL W. MURPHY ---------------------------------------------- ---------------------------------------------- R. Madison Murphy, Chairman and Director Michael W. Murphy, Director CLAIBORNE P. DEMING WILLIAM C. NOLAN JR. ----------------------------------------------- ---------------------------------------------- Claiborne P. Deming, President and Chief William C. Nolan Jr., Director Executive Officer and Director (Principal Executive Officer) B. R. R. BUTLER CAROLINE G. THEUS ---------------------------------------------- ---------------------------------------------- B. R. R. Butler, Director Caroline G. Theus, Director GEORGE S. DEMBROSKI LORNE C. WEBSTER ---------------------------------------------- ---------------------------------------------- George S. Dembroski, Director Lorne C. Webster, Director H. RODES HART STEVEN A. COSSE' ---------------------------------------------- ---------------------------------------------- H. Rodes Hart, Director Steven A. Cosse', Senior Vice President and General Counsel (Principal Financial Officer) VESTER T. HUGHES JR. RONALD W. HERMAN ---------------------------------------------- ---------------------------------------------- Vester T. Hughes Jr., Director Ronald W. Herman, Controller (Principal Accounting Officer) C. H. MURPHY JR. ---------------------------------------------- C. H. Murphy Jr., Director 23

REPORT OF MANAGEMENT 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 accounting principles appropriate in the circumstances and include some amounts based on informed estimates and judgments, with consideration given to materiality. Management is also responsible for maintaining a system of internal accounting controls designed to provide reasonable, but not absolute, assurance that financial information is objective and reliable by ensuring that all transactions are properly recorded in the Company's accounts and records, written policies and procedures are followed and assets are safeguarded. The system is also supported by careful selection and training of qualified personnel. When establishing and maintaining such a system, judgment is required to weigh relative costs against expected benefits. The Company's audit staff independently and systematically evaluates and formally reports on the adequacy and effectiveness of the internal control system. Our independent auditors, KPMG LLP, have audited the consolidated financial statements. Their audit was conducted in accordance with generally accepted auditing standards and provides an independent opinion about the fair presentation of the consolidated financial statements. When performing their audit, KPMG LLP considers the Company's internal control structure to the extent they deem necessary to issue their opinion on the 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 perform an oversight role for the financial statements. This Committee is composed solely of directors who are not employees of the Company. The Committee meets periodically with representatives of management, the Company's audit staff and the independent auditors to review the Company's internal controls, the quality of its financial reporting, and the scope and results of audits. The independent auditors and the Company's audit staff have unrestricted access to the Committee, without management's presence, to discuss audit findings and other financial matters. INDEPENDENT AUDITORS' REPORT The Board of Directors and Stockholders of Murphy Oil Corporation: We have audited the accompanying consolidated balance sheets of Murphy Oil Corporation and Consolidated Subsidiaries as of December 31, 1998 and 1997, 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, 1998. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. 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. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Murphy Oil Corporation and Consolidated Subsidiaries as of December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 1998, in conformity with generally accepted accounting principles. KPMG LLP Shreveport, Louisiana March 1, 1999 F-1

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME YEARS ENDED DECEMBER 31 (THOUSANDS OF DOLLARS EXCEPT PER SHARE AMOUNTS) 1998 1997* 1996* ---- ---- ---- REVENUES Crude oil and natural gas sales $ 312,253 450,785 346,310 Petroleum product sales 1,312,727 1,604,379 1,570,289 Other operating revenues 69,490 78,223 93,137 Interest and other nonoperating revenues 4,378 4,380 12,440 --------- --------- --------- Total revenues 1,698,848 2,137,767 2,022,176 --------- --------- --------- COSTS AND EXPENSES Crude oil, products and related operating expenses 1,279,619 1,527,301 1,483,914 Exploration expenses, including undeveloped lease amortization 65,582 94,792 70,206 Selling and general expenses 61,363 65,928 66,402 Depreciation, depletion and amortization 202,695 209,419 182,381 Impairment of long-lived assets 80,127 28,056 -- Charge resulting from cancellation of a drilling rig contract 7,255 -- -- Interest expense 18,090 12,717 13,120 Interest capitalized (7,606) (12,096) (10,202) --------- --------- --------- Total costs and expenses 1,707,125 1,926,117 1,805,821 --------- --------- --------- Income (loss) from continuing operations before income taxes (8,277) 211,650 216,355 Federal and state income tax expense 18,469 49,062 43,860 Foreign income tax expense (benefit) (12,352) 30,182 46,539 --------- --------- --------- Income (loss) from continuing operations (14,394) 132,406 125,956 Discontinued farm, timber and real estate operations -- -- 11,899 --------- --------- --------- NET INCOME (LOSS) $ (14,394) 132,406 137,855 ========= ========= ========= PER COMMON SHARE - BASIC Continuing operations $ (.32) 2.95 2.80 Discontinued operations -- -- .27 --------- --------- --------- Net income (loss) $ (.32) 2.95 3.07 ========= ========= ========= PER COMMON SHARE - DILUTED Continuing operations $ (.32) 2.94 2.80 Discontinued operations -- -- .27 --------- --------- --------- Net income (loss) $ (.32) 2.94 3.07 ========= ========= ========= Average Common shares outstanding - basic 44,955,679 44,881,225 44,858,115 Average Common shares outstanding - diluted 44,955,679 44,960,907 44,904,636 *Revenues have been reclassified to conform to 1998 presentation. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME YEARS ENDED DECEMBER 31 (THOUSANDS OF DOLLARS) 1998 1997 1996 ---- ---- ---- Net income (loss) $ (14,394) 132,406 137,855 Other comprehensive income - net gain (loss) from foreign currency translation (24,411) (21,682) 18,005 --------- --------- --------- COMPREHENSIVE INCOME (LOSS) $ (38,805) 110,724 155,860 ========= ========= ========= See notes to consolidated financial statements, page F-6. F-2

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED BALANCE SHEETS DECEMBER 31 (THOUSANDS OF DOLLARS) 1998 1997 ---- ---- ASSETS Current assets Cash and cash equivalents $ 28,271 24,288 Accounts receivable, less allowance for doubtful accounts of $11,048 in 1998 and $13,530 in 1997 233,906 272,447 Inventories Crude oil and blend stocks 41,090 55,075 Finished products 49,714 64,394 Materials and supplies 38,973 38,947 Prepaid expenses 32,292 47,323 Deferred income taxes 13,120 15,278 --------- --------- Total current assets 437,366 517,752 Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $2,985,854 in 1998 and $2,762,805 in 1997 1,662,362 1,655,838 Deferred charges and other assets 64,691 64,729 --------- --------- Total assets $ 2,164,419 2,238,319 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Current maturities of long-term debt $ 5,951 6,227 Notes payable 1,961 2,175 Accounts payable 248,967 329,094 Withholdings and collections due governmental agencies 51,606 58,323 Other accrued liabilities 49,314 47,973 Income taxes 22,951 25,627 --------- --------- Total current liabilities 380,750 469,419 Notes payable 189,705 28,367 Nonrecourse debt of a subsidiary 143,768 177,486 Deferred income taxes 124,543 136,390 Reserve for dismantlement costs 154,686 153,021 Reserve for major repairs 43,519 43,038 Deferred credits and other liabilities 149,215 151,247 Stockholders' equity Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued -- -- Common Stock, par $1.00, authorized 80,000,000 shares, issued 48,775,314 shares 48,775 48,775 Capital in excess of par value 510,116 509,615 Retained earnings 545,199 622,532 Accumulated other comprehensive income - foreign currency translation (23,520) 891 Unamortized restricted stock awards (2,361) (944) Treasury stock (99,976) (101,518) --------- --------- Total stockholders' equity 978,233 1,079,351 --------- --------- Total liabilities and stockholders' equity $ 2,164,419 2,238,319 ========= ========= See notes to consolidated financial statements, page F-6. F-3

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS YEARS ENDED DECEMBER 31 (THOUSANDS OF DOLLARS) 1998 1997 1996 ---- ---- ---- OPERATING ACTIVITIES Income (loss) from continuing operations $ (14,394) 132,406 125,956 Adjustments to reconcile above income (loss) to net cash provided by operating activities Depreciation, depletion and amortization 202,695 209,419 182,381 Impairment of long-lived assets 80,127 28,056 -- Provisions for major repairs 20,420 24,614 24,797 Expenditures for major repairs and dismantlement costs (24,582) (14,393) (10,839) Exploratory expenditures charged against income 55,128 84,320 60,532 Amortization of undeveloped leases 10,454 10,472 9,674 Deferred and noncurrent income tax charges (credits) (937) 25,992 28,464 Pretax gains from disposition of assets (3,857) (29,061) (34,369) Other - net 4,504 7,969 5,889 --------- -------- -------- 329,558 479,794 392,485 (Increase) decrease in operating working capital other than cash and cash equivalents (3,810) (72,391) 77,111 Other adjustments related to continuing operations (4,657) (5,560) 2,884 --------- -------- -------- Net cash provided by continuing operations 321,091 401,843 472,480 Net cash provided by discontinued operations -- -- 18,158 --------- -------- -------- Net cash provided by operating activities 321,091 401,843 490,638 --------- -------- -------- INVESTING ACTIVITIES Capital expenditures requiring cash (388,799) (468,031) (418,056) Proceeds from sale of property, plant and equipment 9,463 43,776 55,536 Other continuing operations - net (1,767) 673 (1,128) Investing activities of discontinued operations -- -- (17,402) --------- -------- -------- Net cash required by investing activities (381,103) (423,582) (381,050) --------- -------- -------- FINANCING ACTIVITIES Additions to notes payable 161,342 9,675 -- Reductions of notes payable (218) (4) (776) Additions to nonrecourse debt of a subsidiary 240 6,397 23,089 Reductions of nonrecourse debt of a subsidiary (34,234) (17,276) (10,628) Sale of treasury shares under employee stock purchase plan 552 192 -- Cash dividends paid (62,939) (60,573) (58,294) --------- -------- -------- Net cash provided (required) by financing activities 64,743 (61,589) (46,609) --------- -------- -------- Effect of exchange rate changes on cash and cash equivalents (748) (2,091) 2,277 --------- -------- -------- Net increase (decrease) in cash and cash equivalents 3,983 (85,419) 65,256 Increase applicable to discontinued operations -- -- (16,402) --------- -------- -------- Net increase (decrease) in cash and cash equivalents of continuing operations 3,983 (85,419) 48,854 Cash and cash equivalents of continuing operations at January 1 24,288 109,707 60,853 --------- -------- -------- Cash and cash equivalents of continuing operations at December 31 $ 28,271 24,288 109,707 ========= ======== ======== See notes to consolidated financial statements, page F-6. F-4

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY YEARS ENDED DECEMBER 31 (THOUSANDS OF DOLLARS) 1998 1997 1996 ---- ---- ---- CUMULATIVE PREFERRED STOCK - par $100, authorized 400,000 shares, none issued $ -- -- -- ---------- --------- --------- COMMON STOCK - par $1.00, authorized 80,000,000 shares, issued 48,775,314 shares at beginning and end of year 48,775 48,775 48,775 ---------- --------- --------- CAPITAL IN EXCESS OF PAR VALUE Balance at beginning of year 509,615 509,008 507,758 Exercise of stock options 103 521 450 Restricted stock transactions 142 7 800 Sale of stock under employee stock purchase plan 256 79 -- ---------- --------- --------- Balance at end of year 510,116 509,615 509,008 ---------- --------- --------- RETAINED EARNINGS Balance at beginning of year 622,532 550,699 643,699 Net income (loss) for the year (14,394) 132,406 137,855 Distribution of common stock of Deltic Timber Corporation to stockholders -- -- (172,561) Cash dividends - $1.40 a share in 1998, $1.35 a share in 1997 and $1.30 a share in 1996 (62,939) (60,573) (58,294) ---------- --------- --------- Balance at end of year 545,199 622,532 550,699 ---------- --------- --------- ACCUMULATED OTHER COMPREHENSIVE INCOME - FOREIGN CURRENCY TRANSLATION Balance at beginning of year 891 22,573 4,568 Translation gains (losses) during the year (24,411) (21,682) 18,005 ---------- --------- --------- Balance at end of year (23,520) 891 22,573 ---------- --------- --------- UNAMORTIZED RESTRICTED STOCK AWARDS Balance at beginning of year (944) (1,298) (592) Stock awards (3,238) -- (1,023) Amortization, forfeitures and changes in price of Common Stock 1,821 354 317 ---------- --------- --------- Balance at end of year (2,361) (944) (1,298) ---------- --------- --------- TREASURY STOCK Balance at beginning of year (101,518) (102,279) (103,063) Exercise of stock options 110 526 543 Awarded restricted stock, net of forfeitures 1,136 122 241 Sale of stock under employee stock purchase plan 296 113 -- ---------- --------- --------- Balance at end of year - 3,824,838 shares of Common Stock in 1998, 3,883,883 shares in 1997 and 3,912,971 shares in 1996, at cost (99,976) (101,518) (102,279) ---------- --------- --------- TOTAL STOCKHOLDERS' EQUITY $ 978,233 1,079,351 1,027,478 ========== ========= ========= See notes to consolidated financial statements, page F-6. F-5

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE A - SIGNIFICANT ACCOUNTING POLICIES NATURE OF BUSINESS - Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries. The Company produces oil and natural gas in the United States, Canada, the United Kingdom, and Ecuador, and conducts exploration activities worldwide. The Company has an interest in a Canadian synthetic crude oil operation, the world's largest, and operates two oil refineries in the United States and shares ownership in a U.K. refinery. Murphy markets petroleum products under various brand names and to unbranded wholesale customers in the United States, the United Kingdom, and Canada and transports and trades crude oil in Canada. PRINCIPLES OF CONSOLIDATION - The consolidated financial statements include the accounts of Murphy Oil Corporation and all majority-owned subsidiaries. Investments in affiliates in which the Company owns from 20% to 50% are accounted for by the equity method. Other investments are generally carried at cost. All significant intercompany accounts and transactions have been eliminated. CASH EQUIVALENTS - Short-term investments (which include government securities and other instruments with government securities as collateral) that have a maturity of three months or less from the date of purchase are classified as cash equivalents. INVENTORIES - Inventories of crude oil and refined products are valued at the lower of cost, generally applied on a last-in first-out (LIFO) basis, or market. Materials and supplies are valued at the lower of average cost or estimated value. PROPERTY, PLANT AND EQUIPMENT - The Company uses the successful efforts method to account for exploration and development expenditures. Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Significant undeveloped leases are reviewed periodically and a valuation allowance is provided for any estimated decline in value. Cost of other undeveloped leases is expensed over the estimated average life of the leases. Cost of exploratory drilling is initially capitalized but is subsequently expensed if proved reserves are not found. Other exploratory costs are charged to expense as incurred. Development costs, including unsuccessful development wells, are capitalized. Oil and gas properties are evaluated by field for potential impairment; other long-lived assets are evaluated on a specific asset basis or in groups of similar assets, as applicable. An impairment is recognized when the undiscounted estimated future net cash flows of an evaluated asset are less than its carrying value. Depreciation and depletion of producing oil and gas properties are provided based on units of production. Unit rates are computed for unamortized development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Estimated dismantlement, abandonment and site restoration costs, net of salvage value, are considered in determining depreciation and depletion. Refining and marketing facilities are depreciated using the composite straight-line method. Other properties are depreciated by individual unit on the straight-line method. Gains and losses on disposals or retirements that are significant or include an entire depreciable or depletable property unit are included in income. Costs of dismantling oil and gas production facilities and site restoration are charged against the related reserve. All other dispositions, retirements or abandonments are reflected in accumulated depreciation, depletion and amortization. Provisions for turnarounds of refineries and a synthetic oil upgrading facility are charged to expense monthly. Costs incurred are charged against the reserve. All other maintenance and repairs are expensed. Renewals and betterments are capitalized. F-6

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) ENVIRONMENTAL LIABILITIES - A provision for environmental obligations is charged to expense when the Company's liability for an environmental assessment and/or cleanup is probable and the cost can be reasonably estimated. Related expenditures are charged against the reserve. Environmental remediation liabilities have not been discounted for the time value of future expected payments. Environmental expenditures that have future economic benefit are capitalized. INCOME TAXES - The Company accounts for income taxes using the asset and liability method. Under this method, income taxes are provided for amounts currently payable, and for amounts deferred as tax assets and liabilities based on differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities. Deferred income taxes are measured using the enacted tax rates that are assumed will be in effect when the differences reverse. U.K. petroleum revenue taxes are provided using the estimated effective tax rate over the life of applicable U.K. properties. FOREIGN CURRENCY - Local currency is the functional currency used for recording operations in Canada and Spain and the majority of activities in the United Kingdom. The U.S. dollar is the functional currency used to record all other operations. Gains or losses from translating foreign functional currency into U.S. dollars are included in "Accumulated Other Comprehensive Income" on the Consolidated Balance Sheets. Exchange gains or losses from transactions in a currency other than the functional currency are included in income. DERIVATIVE INSTRUMENTS - The Company uses derivative instruments on a limited basis to manage certain risks related to interest rates, foreign currency exchange rates and commodity prices. Instruments that reduce the exposure of assets, liabilities or anticipated transactions to interest rate, currency or price risks are accounted for as hedges. Gains and losses on derivatives that cease to qualify as hedges are recognized in income or expense. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company's senior management. The Company does not hold any derivatives for trading purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded either with creditworthy major financial institutions or over national exchanges. Net cash to be paid or received on an interest rate swap is recognized as an adjustment of "Interest Expense." If the Company terminates an interest rate swap prior to maturity, any cash paid or received as settlement would be deferred and recognized as an adjustment to "Interest Expense" over the shorter of the remaining life of the debt or the remaining contractual life of the swap. Gains or losses on foreign exchange contracts are recognized in income or as adjustments to the carrying amounts of hedged items. Gains or losses on settlement of crude oil swaps are included in costs in the periods that the hedged oil purchases occur. A loss is recognized if the estimated cost of the future crude oil purchases, including projected settlement costs of the swap contracts, exceeds the estimated net realizable value of the related finished products. EXCISE TAXES ON REFINED PRODUCTS - Taxes collected on the sales of refined products and remitted to governmental agencies are not included in revenues or in costs and expenses. NET INCOME PER COMMON SHARE - Basic income per Common share is computed by dividing net income for each reporting period by the weighted average number of Common shares outstanding during the period. Diluted income per Common share is computed by dividing net income for each reporting period by the weighted average number of Common shares outstanding during the period plus the effects of potentially dilutive Common shares. USE OF ESTIMATES - In preparing the financial statements of the Company in conformity with generally accepted accounting principles, management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates. F-7

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) NOTE B - DISCONTINUED OPERATIONS On December 31, 1996, Murphy completed a tax-free spin-off to its stockholders of all the common stock of its wholly owned farm, timber and real estate subsidiary, Deltic Farm & Timber Co., Inc. (reincorporated as "Deltic Timber Corporation"). The spin-off resulted in a net charge of $172,561,000 to "Retained Earnings" in 1996. Farm, timber and real estate activities have been accounted for as discontinued operations. Selected operating results for these activities, presented as a net amount in the Consolidated Statements of Income for 1996 were: revenues of $87,746,000; income tax provision of $8,878,000; income from operations of $13,999,000, $.31 a diluted share; and costs of spin-off transaction of $2,100,000, $(.04) a diluted share. NOTE C - PROPERTY, PLANT AND EQUIPMENT INVESTMENT INVESTMENT DECEMBER 31, 1998 DECEMBER 31, 1997 --------------------- --------------------- (THOUSANDS OF DOLLARS) COST NET COST NET ---------- --------- --------- --------- Exploration and production $3,657,399 1,228,477* 3,476,167 1,235,373* Refining 677,245 257,640 649,374 254,032 Marketing 196,362 116,958 178,179 104,305 Transportation 81,307 40,459 80,819 42,125 Corporate and other 35,903 18,828 34,104 20,003 ---------- --------- --------- --------- $4,648,216 1,662,362 4,418,643 1,655,838 ========== ========= ========= ========= *Includes $15,766 in 1998 and $17,084 in 1997 related to administrative assets and support equipment. In 1998 and 1997, the Company recorded noncash charges of $80,127,000 and $28,056,000, respectively, for impairment of certain long-lived assets. After related income tax benefits, these write-downs reduced net income by $57,573,000 in 1998 and $16,224,000 in 1997. The 1998 charges resulted from management's expectation of a continuation of the low-price environment for sales of crude oil and natural gas that existed at the end of 1998; the write-down included certain oil and gas assets in the U.S. Gulf of Mexico, the U.K. North Sea, China, and Canada and certain marketing assets in Canada. The 1997 charges related to certain investments in Canadian heavy oil fields that were not adequately supported by reserves and three natural gas fields in the Gulf of Mexico that depleted earlier than anticipated. The carrying values for assets determined to be impaired were adjusted to estimated fair values based on projected future discounted net cash flows for such assets. NOTE D - FINANCING ARRANGEMENTS At December 31, 1998, the Company had a committed credit facility with a major banking consortium of an equivalent US $300,000,000 for a combination of U.S. dollar and Canadian dollar borrowings, of which an equivalent US $113,842,000 was outstanding and classified as long-term notes payable. In addition, the Company had committed facilities with major banks of US $117,220,000 subject to drawdown based on the availability of loan guarantees from the Canadian government. Depending on the credit facility, borrowings bear interest at prime or varying cost of fund options. Facility fees are due at varying rates on certain of the commitments. The facilities expire at dates ranging from 1999 through 2002. At December 31, 1998 and 1997, U.S. dollar and Canadian dollar commercial paper and bankers' acceptances totaling an equivalent US $115,733,000 and US $118,834,000, respectively, supported by bank credit facilities, were classified as nonrecourse debt. In addition, the Company had uncommitted lines of credit with banks at December 31, 1998, totaling an equivalent US $191,911,000 for a combination of U.S. dollar and Canadian dollar borrowings. At December 31, 1998, an equivalent US $56,961,000 of debt was outstanding under these uncommitted lines, $55,000,000 of which is planned to be refinanced under an existing committed credit facility and is reflected as long-term notes payable. At the end of 1998, the Company had a shelf registration on file with the U.S. Securities and Exchange Commission that would permit the offer and sale of $250,000,000 in debt securities. No securities had been issued as of December 31, 1998. F-8

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) NOTE E - LONG-TERM DEBT DECEMBER 31 (THOUSANDS OF DOLLARS) 1998 1997 ---- ---- Notes payable Notes payable to bank, 10.1%, due 2004 $ 20,000 20,000 Notes payable to banks, 5.30% to 5.35%, $7,842 payable in Canadian dollars, due 2002 168,842 7,500 Other, 6% and 8%, due 1999-2021 867 871 --------- ------- Total notes payable 189,709 28,371 --------- ------- Nonrecourse debt of a subsidiary Guaranteed credit facilities with banks Commercial paper, 4.98% to 5.28%, $40,386 payable in Canadian dollars, supported by credit facility, due 2001-2008 109,786 112,611 Bankers' acceptance, 5.27%, payable in Canadian dollars, supported by credit facility, due 1999 5,947 6,223 Loan payable to Canadian government, interest free, payable in Canadian dollars, due 1999-2008 33,982 36,358 Promissory note, 6.25%, payable in Canadian dollars, due 1998 -- 28,517 --------- ------- Total nonrecourse debt of a subsidiary 149,715 183,709 --------- ------- Total including current maturities 339,424 212,080 Current maturities (5,951) (6,227) --------- ------- Total long-term debt $ 333,473 205,853 ========= ======= Amounts becoming due for the four years after 1999 are: $5,000 each in 2000 and 2001; $200,149,000 in 2002; and $13,795,000 in 2003. The nonrecourse guaranteed credit facilities were arranged to finance certain expenditures for the Hibernia oil field. Subject to certain conditions and limitations, the Canadian government has unconditionally guaranteed repayment of amounts drawn under the facilities to lenders having qualifying Participation Certificates. The Company has borrowed the maximum amount available under the Primary Guarantee Facility at December 31, 1998. The amount guaranteed declines quarterly beginning in 2001, at which time repayment will begin based on the greater of 30% of Murphy's after-tax free cash flow from Hibernia or equal quarterly payments over eight years. The payment for 2001 is planned to be refinanced under an existing committed credit facility and is thereby reflected as becoming due in 2002. No guaranteed financing is available after January 1, 2016. A guarantee fee of .5% is payable annually in arrears to the Canadian government. The interest free loan from the Canadian government was also used to finance expenditures for the Hibernia field. Repayment will begin in 1999, but payments through 2001 are planned to be refinanced under an existing committed credit facility and are thereby reflected as becoming due in 2002. NOTE F - INCOME TAXES The components of income (loss) from continuing operations before income taxes were: (THOUSANDS OF DOLLARS) 1998 1997 1996 ---- ---- ---- United States $ 44,600 135,476 104,888 Foreign (52,877) 76,174 111,467 -------- ------- ------- $ (8,277) 211,650 216,355 ======== ======= ======= F-9

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The components of income tax expense (benefit) were: (THOUSANDS OF DOLLARS) 1998 1997 1996 ---- ---- ---- Income tax expense (benefit) Continuing operations Federal - Current* $ 6,431 31,278 16,445 Deferred 6,232 (1,751) 15,837 Noncurrent 3,785 14,946 8,762 ------ ------ ------ 16,448 44,473 41,044 ------ ------ ------ State - Current 2,021 4,589 2,816 ------ ------ ------ Foreign - Current (3,498) 12,912 46,130 Deferred (10,201) 19,423 4,095 Noncurrent 1,347 (2,153) (3,686) ------ ------ ------ (12,352) 30,182 46,539 ------ ------ ------ Total from continuing operations 6,117 79,244 90,399 Discontinued operations -- -- 8,878 ------ ------ ------ Total income tax expense $ 6,117 79,244 99,277 ====== ====== ====== *Net of benefits of $12,537 in 1997 and $1,035 in 1996 for alternative minimum tax credits. Noncurrent taxes, classified in the Consolidated Balance Sheets as a component of "Deferred Credits and Other Liabilities," relate primarily to matters not resolved with various taxing authorities. The significant components of deferred income tax expense (benefit) attributable to income (loss) from continuing operations before income taxes for the three years ended December 31, 1998, were: (THOUSANDS OF DOLLARS) 1998 1997 1996 ---- ---- ---- Deferred tax expense (benefit) excluding the effects of the items below on deferred tax assets and liabilities $ (1,901) 13,180 17,754 Estimated tax credit carryforward (increase) decrease (2,068) 6,065 2,178 Effect of change in U.K. tax rate -- (1,573) -- ------ ------ ------ Total deferred tax expense (benefit) $ (3,969) 17,672 19,932 ====== ====== ====== The following table reconciles theoretical income taxes, based on the U.S. statutory tax rate, to the Company's income tax expense from continuing operations. (THOUSANDS OF DOLLARS) 1998 1997 1996 ---- ---- ---- Theoretical income tax expense (benefit) based on the U.S. statutory tax rate $ (2,897) 74,078 75,724 Foreign asset impairment with no tax benefit 5,293 -- -- Foreign income subject to foreign taxes at greater than U.S. statutory rate 4,671 7,711 14,641 State income taxes 1,313 2,983 1,831 Refund and settlement of foreign taxes (1,410) (3,163) (2,945) Refund and settlement of U.S. taxes (704) -- -- Other, net (149) (2,365) 1,148 ------ ------ ------ Total income tax expense from continuing operations $ 6,117 79,244 90,399 ====== ====== ====== F-10

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) An analysis of the Company's deferred tax assets and deferred tax liabilities at December 31, 1998 and 1997, showing the tax effects of significant temporary differences follows. (THOUSANDS OF DOLLARS) 1998 1997 ---- ---- Deferred tax assets Property and leasehold costs $ 75,716 76,516 Reserves for dismantlements and major repairs 63,763 64,206 Federal alternative minimum tax credit carryforward 2,068 -- Postretirement and other employee benefits 17,979 21,146 Other deferred tax assets 24,234 24,873 ------- ------- Total gross deferred tax assets 183,760 186,741 Less valuation allowance (47,294) (47,228) ------- ------- Net deferred tax assets 136,466 139,513 ------- ------- Deferred tax liabilities Property, plant and equipment (34,152) (41,069) Accumulated depreciation, depletion and amortization (189,082) (194,540) Other deferred tax liabilities (24,686) (25,117) ------- ------- Total gross deferred tax liabilities (247,920) (260,726) ------- ------- Net deferred tax liabilities $(111,454) (121,213) ======= ======= In management's judgment, the net deferred tax assets in the preceding table will more likely than not be realized as reductions of future taxable income or by utilizing available tax planning strategies. The valuation allowance for deferred tax assets relates primarily to tax assets arising in foreign tax jurisdictions, and in the judgment of management, these tax assets are not likely to be realized. The valuation allowance increased $66,000 in 1998 and $13,619,000 in 1997; the change in each year offset the change in certain deferred tax assets. Any subsequent reductions of the valuation allowance will be reported as reductions of income tax expense assuming no offsetting change in the deferred tax asset. The Company has not recorded a deferred tax liability of $19,700,000 related to undistributed earnings of certain foreign subsidiaries at December 31, 1998, because the earnings are considered permanently invested. Income tax returns are subject to audit by the U.S. Internal Revenue Service and other taxing authorities. In 1998, 1997 and 1996, the Company recorded benefits to income of $2,114,000, $3,163,000 and $5,120,000, respectively, from refunds and settlements of various U.S. and foreign tax issues primarily related to prior years. The Company believes that adequate accruals have been made for unsettled issues. NOTE G - INCENTIVE PLANS The Company's 1992 Stock Incentive Plan (the Plan) authorized the Executive Compensation and Nominating Committee (the Committee) to make annual grants of the Company's Common Stock to executives and other key employees as follows: (1) stock options (nonqualified or incentive), (2) stock appreciation rights (SAR), and/or (3) restricted stock. Annual grants may not exceed .5% of shares outstanding at the end of the preceding year; allowed shares not granted may be granted in future years. The Company uses APB Opinion No. 25 to account for stock-based compensation, accruing costs of options and restricted stock over the vesting/performance periods and adjusting costs for subsequent changes in fair market value of the shares. Compensation cost charged against (credited to) income for stock-based plans was $(4,646,000) in 1998, $2,026,000 in 1997 and $5,566,000 in 1996; outstanding awards were not significantly modified in the last three years. Had compensation cost of these stock-based plans been based on the fair value of the instruments at date of grant using the provisions of Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock-Based Compensation," the Company's net income and earnings per share would be the pro forma amounts shown in the following table. The pro forma effects on net income in the table may not be representative of the pro forma effects on net income of future years because the SFAS No. 123 provisions used in these calculations were only applied to stock options and restricted stock granted after 1994. F-11

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (THOUSANDS OF DOLLARS EXCEPT PER SHARE DATA) 1998 1997 1996 ---- ---- ---- Net income (loss) - As reported $ (14,394) 132,406 137,855 Pro forma (18,182) 132,089 138,570 Earnings per share - As reported, basic $ (.32) 2.95 3.07 Pro forma, basic (.40) 2.94 3.09 As reported, diluted (.32) 2.94 3.07 Pro forma, diluted (.40) 2.94 3.09 STOCK OPTIONS - The Committee fixes the option price of each option granted at no less than fair market value (FMV) on the date of the grant and fixes the option term at no more than 10 years from such date. Each option granted to date under the Plan has had a term of 10 years, has been nonqualified, and has had an option price equal to FMV at date of grant, except for certain 1997 grants with option prices above FMV. One-half of each grant may be exercised after two years and the remainder after three years. At exercise, a grantee may pay cash for shares, or alternatively, not remit cash and receive shares equal to the inherent value of options exercised on that date. The number of outstanding options at January 1, 1997, and the related option prices were adjusted to preserve the existing economic values of the options at the time of the Deltic spin-off. The pro forma net income calculations in the preceding table reflect the following weighted-average fair values of options granted in 1998, 1997 and 1996; fair values of options have been estimated by using the Black-Scholes pricing model and the assumptions as shown. 1998 1997 1997 1996 FMV Above FMV FMV FMV ---- --------- ---- ---- Weighted-average fair value per share at grant date $ 9.01 8.25 9.75 7.27 Weighted-average assumptions Dividend yield 2.91% 3.00% 3.00% 3.20% Expected volatility 17.27% 17.37% 17.37% 17.64% Risk-free interest rate 5.46% 6.37% 6.18% 5.26% Expected life 5 yrs. 7 yrs. 5 yrs. 5 yrs. Changes in options outstanding, including shares issued under a prior plan, were: AVERAGE NUMBER EXERCISE OF SHARES PRICE --------- -------- Outstanding at December 31, 1995 425,230 $ 39.28 Granted at FMV 168,000 42.44 Exercised (105,006) 36.47 Forfeited (47,625) 42.82 --------- Outstanding at December 31, 1996 440,599 40.77 Deltic spin-off adjustment 17,407 -- Granted at FMV 180,250 50.38 Granted above FMV 231,750 60.45 Exercised (68,022) 36.53 Forfeited (31,295) 49.08 --------- Outstanding at December 31, 1997 770,689 48.04 Granted at FMV 312,000 49.75 Exercised (17,400) 36.04 Forfeited (12,040) 49.34 --------- Outstanding at December 31, 1998 1,053,249 48.73 ========= Exercisable at December 31, 1996 153,223 $ 36.92 Exercisable at December 31, 1997 174,269 37.79 Exercisable at December 31, 1998 284,529 39.53 F-12

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Additional information about stock options outstanding at December 31, 1998, is shown below. OPTIONS OUTSTANDING OPTIONS EXERCISABLE ---------------------------------------- ------------------------ RANGE OF NO. OF AVG. LIFE AVG. NO. OF AVG. EXERCISE PRICES OPTIONS IN YEARS PRICE OPTIONS PRICE - - ---------------- ------- --------- ------ ------- ----- $30.29 to $39.42 109,289 3.6 $ 36.10 109,289 $ 36.10 $40.81 to $42.25 245,960 6.6 41.43 175,240 41.68 $49.75 to $50.38 477,500 8.7 49.97 -- -- $55.41 to $65.49 220,500 8.1 60.45 -- -- --------- ------- Total outstanding 1,053,249 7.6 48.73 284,529 39.53 ========= ======= SAR - SAR may be granted in conjunction with or independent of stock options; the Committee determines when SAR may be exercised and the price. No SAR have been granted. RESTRICTED STOCK - Since 1992, shares of restricted stock have been granted in alternate years. Each grant will vest if the Company achieves specific financial objectives at the end of a five-year performance period. Additional shares may be awarded if objectives are exceeded, but some or all shares may be forfeited if objectives are not met. During the performance period, a grantee may vote and receive dividends on the shares, but shares are subject to transfer restrictions and are all or partially forfeited if a grantee terminates. The Company may reimburse a grantee up to 50% of the award value for personal income tax liability on stock awarded. For the pro forma net income calculation, the fair values per share of restricted stock granted in 1998 and 1996 were $49.50 and $42.88, the respective market prices of the stock at the dates granted. On December 31, 1996, 50% of eligible shares granted in 1992 were awarded and the remaining shares were forfeited based on financial objectives achieved. The number of restricted shares outstanding at January 1, 1997, was adjusted to preserve the existing economic value of the stock at the time of the Deltic spin-off. On December 31, 1998, all shares granted in 1994 were forfeited because financial objectives were not achieved. Changes in restricted stock outstanding were: (NUMBER OF SHARES) 1998 1997 1996 ---- ---- ---- Balance at beginning of year 39,856 36,512 38,011 Granted 59,750 -- 24,250 Grant adjustment to reflect Deltic spin-off -- 5,977 -- Awarded -- (1,336)* (10,563) Forfeited (16,242) (1,297) (15,186) ------ ------ ------ Balance at end of year 83,364 39,856 36,512 ====== ====== ====== *Additional shares awarded related to Deltic spin-off. CASH AWARDS - The Committee also administers the Company's incentive compensation plans, which provide for annual or periodic cash awards to officers, directors and key employees if the Company achieves specific financial objectives. Compensation expense of $518,000, $3,894,000 and $3,100,000 was recorded in 1998, 1997 and 1996, respectively, for these plans. EMPLOYEE STOCK PURCHASE PLAN (ESPP) - In 1997, the Company's shareholders approved the ESPP, under which 50,000 shares of the Company's Common Stock could be purchased by employees. Each quarter, an eligible U.S. employee may elect to withhold up to 10% of his or her salary to purchase shares of the Company's stock at a price equal to 90% of the fair value of the stock as of the first day of the quarter. The ESPP will terminate on the earlier of the date that employees have purchased all 50,000 shares or June 30, 2002. Employee stock purchases under the ESPP were 11,315 shares at an average price of $48.81 a share in 1998 and 4,326 shares at $44.44 in 1997. At December 31, 1998, 34,359 shares remained available for sale under the ESPP. Compensation costs related to the ESPP were immaterial. F-13

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE H - EMPLOYEE AND RETIREE BENEFIT PLANS PENSION AND POSTRETIREMENT PLANS - The Company has noncontributory defined benefit pension plans that cover substantially all full-time employees. In addition, the Company sponsors plans that provide health care and life insurance benefits for most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory. The tables that follow provide a reconciliation of the changes in the plans' benefit obligations and fair value of assets for the years ended December 31, 1998 and 1997, and a statement of the funded status as of December 31, 1998 and 1997. PENSION POSTRETIREMENT BENEFITS BENEFITS ---------------------------- -------------------------- (THOUSANDS OF DOLLARS) 1998 1997 1998 1997 ---- ---- ---- ---- CHANGE IN BENEFIT OBLIGATION Obligation at January 1 $ 220,981 193,923 36,255 34,228 Service cost 5,242 4,517 601 508 Interest cost 15,309 14,889 2,474 2,466 Plan amendments 2,744 1,046 -- -- Participant contributions -- -- 535 561 Actuarial loss 8,492 20,612 496 1,938 Exchange rate changes (908) (1,081) -- -- Benefits paid (13,838) (12,925) (3,612) (3,446) ---------- -------- -------- -------- Obligation at December 31 238,022 220,981 36,749 36,255 ---------- -------- -------- -------- CHANGE IN PLAN ASSETS Fair value of plan assets at January 1 269,794 230,290 -- -- Actual return on plan assets 30,727 52,992 -- -- Employer contributions 1,373 912 3,077 2,885 Participant contributions -- -- 535 561 Exchange rate changes (1,210) (1,475) -- -- Benefits paid (13,838) (12,925) (3,612) (3,446) ---------- -------- -------- -------- Fair value of plan assets at December 31 286,846 269,794 -- -- ---------- -------- -------- -------- RECONCILIATION OF FUNDED STATUS Funded status at December 31 48,824 48,813 (36,749) (36,255) Unrecognized actuarial (gain) loss (30,410) (31,296) 6,730 6,428 Unrecognized transition asset (10,960) (13,339) -- -- Unrecognized prior service cost 6,813 4,668 -- -- ---------- -------- -------- -------- Net plan asset (liability) recognized $ 14,267 8,846 (30,019) (29,827) ========== ======== ======== ======== AMOUNTS RECOGNIZED IN THE CONSOLIDATED BALANCE SHEETS AT DECEMBER 31 Prepaid benefit asset $ 29,477 24,311 -- -- Accrued benefit liability (16,087) (15,983) (30,019) (29,827) Intangible asset 877 518 -- -- ---------- -------- -------- -------- Net plan asset (liability) recognized $ 14,267 8,846 (30,019) (29,827) ========== ======== ======== ======== The Company's U.S. and Canadian nonqualified and U.S. directors' retirement plans were the only pension plans with accumulated benefit obligations in excess of plan assets at December 31, 1998 and 1997. The plans' accumulated benefit obligations at December 31, 1998 and 1997, were $7,486,000 and $6,381,000, respectively; there were no assets in these plans. The Company's postretirement benefit plan also had no plan assets; the benefit obligation for this plan at December 31, 1998 and 1997, was $30,019,000 and $29,827,000, respectively. F-14

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The table that follows provides the components of net periodic benefit expense (credit) for the three years ended December 31, 1998. PENSION BENEFITS POSTRETIREMENT BENEFITS ------------------------------------ ----------------------------------- (THOUSANDS OF DOLLARS) 1998 1997 1996 1998 1997 1996 ---- ---- ---- ---- ---- ---- Service cost $ 5,242 4,517 4,719 601 508 714 Interest cost 15,309 14,889 14,229 2,474 2,466 2,175 Expected return on plan assets (22,180) (19,040) (18,361) -- -- -- Amortization of prior service cost 626 402 354 -- -- -- Amortization of transitional asset (2,211) (2,216) (2,260) -- -- -- Recognized actuarial (gain) loss (758) (965) (736) 194 67 17 -------- -------- -------- ------- -------- ------- Net periodic benefit expense (credit) $ (3,972) (2,413) (2,055) 3,269 3,041 2,906 ======== ======== ======== ======= ======== ======= The preceding tables include the following amounts related to foreign benefit plans. PENSION POSTRETIREMENT BENEFITS BENEFITS --------------------- ---------------------- (THOUSANDS OF DOLLARS) 1998 1997 1998 1997 ---- ---- ---- ---- Obligation at December 31 $47,625 42,871 -- -- Fair value of plan assets at December 31 54,348 49,014 -- -- Net plan liability recognized (3,285) (3,361) -- -- Net periodic benefit expense 410 23 -- -- The following table provides the weighted-average assumptions used in the measurement of the Company's benefit obligations at December 31, 1998 and 1997. PENSION POSTRETIREMENT BENEFITS BENEFITS ------------------------ ------------------------ 1998 1997 1998 1997 ---- ---- ---- ---- Discount rate 6.62% 7.03% 6.75% 7.00% Expected return on plan assets 8.31% 8.43% -- -- Rate of compensation increase 4.67% 4.81% -- -- For purposes of measuring postretirement benefit obligations, a 7.5% annual rate of increase in the cost of health care was assumed at December 31, 1998 and 1997. The rate of increase was assumed to decrease gradually each year to a rate of 4.5% for 2002 and beyond. Assumed health care cost trend rates have a significant effect on the expense and obligation reported for the postretirement benefit plan. A 1% change in assumed health care cost trend rates would have the following effects. (THOUSANDS OF DOLLARS) 1% INCREASE 1% DECREASE ----------- ----------- Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 1998 $ 224 (213) Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 1998 2,394 (2,327) THRIFT PLANS - Most U.S. and Canadian employees of the Company may participate in thrift plans by allotting up to a specified percentage of their base pay. The Company matches contributions at a stated percentage of each employee's allotment based on years of participation in the plans. Company contributions to these plans were $3,333,000 in 1998, $3,076,000 in 1997 and $2,784,000 in 1996, including $190,000 in 1996 that was included in "Discontinued Farm, Timber and Real Estate Operations" in the Consolidated Statements of Income. F-15

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) NOTE I - FINANCIAL INSTRUMENTS DERIVATIVE INSTRUMENTS - As discussed in Note A, Murphy utilizes derivative instruments on a limited basis to manage risks related to interest rates, foreign currency exchange rates and commodity prices. At December 31, 1998 and 1997, the Company had interest rate swap agreements with notional amounts totaling $100,000,000 that serve to convert an equal amount of variable rate long-term debt to fixed rates. The swaps mature in 2002 and 2004. The swaps require Murphy to pay a weighted-average interest rate of 6.46% over their composite lives and to receive a variable rate, which averaged 5.23% at December 31, 1998. Using the accrual/settlement method of accounting, the Company records the net amount to be received or paid under the swap agreements as part of "Interest Expense" in the Consolidated Statements of Income. At December 31, 1997, the Company had a forward foreign currency exchange contract that served to fix the U.S. dollar cost for Canadian dollar nonrecourse debt associated with the Company's investment in the Syncrude project. The currency exchange contract matured and the related debt was retired in December 1998. During the life of the contract, the Company recorded the unrealized difference between the contract exchange rate and the actual exchange rate on the Consolidated Balance Sheet as an adjustment to "Nonrecourse Debt of a Subsidiary," with the offset to "Accumulated Other Comprehensive Income." The Company previously used crude oil swap agreements to reduce a portion of the financial exposure of its U.S. refineries to crude oil price movements. Unrealized gains or losses on such swap contracts were generally deferred and recognized in connection with the associated crude oil purchase. If conditions indicated that the market price of finished products would not allow for recovery of the costs of the finished products, including any unrealized loss on the crude oil swap, a liability was provided for the nonrecoverable portion of the unrealized swap loss. The final swap matured in 1997. The Company recorded pretax operating results associated with crude oil swaps in "Crude Oil, Products and Related Operating Expenses" in the Consolidated Statements of Income. For 1997 and 1996, after-tax gains from crude oil swaps were $5,041,000 and $9,209,000, respectively. FAIR VALUE - The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 1998 and 1997. The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties. The table excludes cash and cash equivalents, trade accounts receivable, investments and noncurrent receivables, trade accounts payable, and accrued expenses, all of which had fair values approximating carrying amounts. 1998 1998 1997 1997 CARRYING ESTIMATED CARRYING ESTIMATED (THOUSANDS OF DOLLARS) AMOUNT FAIR VALUE AMOUNT FAIR VALUE ------- ---------- ------- ---------- FINANCIAL LIABILITIES Current and long-term debt $(341,385) (333,905) (214,255) (205,240) OFF-BALANCE-SHEET EXPOSURES Interest rate swaps -- (5,453) -- (1,886) Financial guarantees and letters of credit -- -- -- -- The carrying amounts of financial liabilities in the preceding table are included in the Consolidated Balance Sheets under "Current Maturities of Long-Term Debt," "Notes Payable," and "Nonrecourse Debt of a Subsidiary." The following methods and assumptions were used to estimate the fair value of each class of financial instruments shown in the table. . Current and long-term debt - The fair value is estimated based on current rates offered the Company for debt of the same maturities. . Interest rate swaps - The fair value is an estimate of the amounts, based on quotes from counterparties, that the Company would pay at the reporting date to cancel the contracts. . Financial guarantees and letters of credit - The fair value, which represents fees associated with obtaining the instruments, was nominal. F-16

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) CREDIT RISKS - The Company's primary credit risks are associated with trade accounts receivable, cash equivalents and derivative instruments. Trade receivables arise mainly from sales of crude oil, natural gas and petroleum products to a large number of customers in the United States, Canada and the United Kingdom. The credit history and financial condition of potential customers are reviewed before credit is extended, security is obtained when deemed appropriate based on a potential customer's financial condition, and routine follow-up evaluations are made. The combination of these evaluations and the large number of customers tends to limit the risk of credit concentration to an acceptable level. Cash equivalents are placed with several major financial institutions; this limits the Company's exposure to credit risk. The Company controls credit risk on derivatives through credit approvals and monitoring procedures and believes that such risks are minimal because counterparties to the transactions are major financial institutions. NOTE J - STOCKHOLDER RIGHTS PLAN The Company's Stockholder Rights Plan provides for each Common stockholder to receive a dividend of one Right for each share of the Company's Common Stock held. The Rights will expire on April 6, 2008, unless earlier redeemed or exchanged. The Rights will detach from the Common Stock and become exercisable following a specified period of time after the first public announcement that a person or group of affiliated or associated persons (other than certain persons) has become the beneficial owner of 15% or more of the Company's Common Stock. The Rights have certain antitakeover effects and will cause substantial dilution to a person or group that attempts to acquire the Company without conditioning the offer on a substantial number of Rights being acquired. The Rights are not intended to prevent a takeover, but rather are designed to enhance the ability of the Board of Directors to negotiate with an acquiror on behalf of all shareholders. Other terms of the Rights are set forth in, and the foregoing description is qualified in its entirety by, the Rights Agreement between the Company and Harris Trust Company of New York, as Rights Agent. NOTE K - EARNINGS PER SHARE A reconciliation of the weighted-average shares outstanding for computation of basic and diluted income (loss) per Common share for the three years ended December 31, 1998 follows. No difference existed between net income (loss) used in computing basic and diluted income (loss) per Common share for these years. (WEIGHTED-AVERAGE SHARES OUTSTANDING) 1998 1997 1996 ---- ---- ---- Basic method 44,955,679 44,881,225 44,858,115 Dilutive stock options -- 79,682 46,521 ---------- ---------- ---------- Diluted method 44,955,679 44,960,907 44,904,636 ========== ========== ========== Stock options to acquire 1,053,249 shares in 1998, 346,306 shares in 1997 and 140,692 shares in 1996 were not considered in the computation of diluted earnings per share because the effects of these options would have improved the Company's earnings per share. NOTE L - OTHER FINANCIAL INFORMATION INVENTORIES - At December 31, 1998, the Company wrote down certain crude oil inventories to market value, resulting in a charge to income of $6,792,000 ($4,227,000 after tax). After the write-down, inventories accounted for under the LIFO method totaled $65,107,000 and $82,709,000 at December 31, 1998 and 1997, respectively, which were $14,695,000 and $76,008,000 less than such inventories would have been valued using the FIFO method. FOREIGN CURRENCY - Cumulative translation gains and losses, net of insignificant related income tax effects, are included in "Accumulated Other Comprehensive Income" in the Consolidated Balance Sheets. At December 31, 1998, components of the net cumulative loss of $23,520,000 were gains (losses) of $37,535,000 for pounds sterling, $(61,884,000) for Canadian dollars and $829,000 for other currencies. Comparability of net income was not significantly affected by exchange rate fluctuations in 1998, 1997 or 1996. Net gains (losses) from foreign currency transactions included in the Consolidated Statements of Income were $282,000 in 1998, $200,000 in 1997 and $(175,000) in 1996. F-17

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) CASH FLOW DISCLOSURES - Cash income taxes paid, net of refunds, were $26,227,000, $86,962,000 and $51,983,000 in 1998, 1997 and 1996. Interest paid, net of amounts capitalized, was $9,551,000, $269,000 and $1,659,000 in 1998, 1997 and 1996. Changes in noncash operating working capital for the three years ended December 31, 1998, were: (THOUSANDS OF DOLLARS) 1998 1997 1996 ---- ---- ---- Accounts receivable $ 38,541 47,214 (89,453) Inventories 28,639 (27,061) 22,558 Prepaid expenses 15,031 (17,503) (1,679) Deferred income tax assets 2,158 4,348 (2,234) Accounts payable and accrued liabilities (85,503) (67,623) 131,774 Current income tax liabilities (2,676) (11,766) 16,145 -------- -------- ------- Net (increase) decrease in noncash operating working capital $ (3,810) (72,391) 77,111 ======== ======== ======= NOTE M - COMMITMENTS The Company leases land, service stations and other facilities under operating leases. Future minimum rental commitments under noncancellable operating leases are not material. Commitments for capital expenditures were approximately $209,000,000 at December 31, 1998, including $90,000,000 related to one third of a multiyear contract for a semisubmersible drilling rig capable of drilling in 6,000 feet of water. Delivery of the rig is scheduled for 1999. NOTE N - CONTINGENCIES The Company's operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax increases and retroactive tax claims; restrictions on production; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company's relationships with employees, suppliers, customers, stockholders and others. Because governmental actions are often motivated by political considerations, may be taken without full consideration of their consequences, and may be taken in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company. FOREIGN CRUDE OIL CONTRACTS - In August 1996, the Ecuadoran government notified the Company that its risk service contract for production of crude oil in Ecuador would be replaced by a production sharing contract effective January 1, 1997, to give the government a larger share of future oil revenues. While the state oil company, PetroEcuador, acknowledged that amounts were owed under the former contract and indicated its intention to pay, the Company considered the circumstances surrounding the contract replacement and recorded an $8,876,000 provision for doubtful accounts at December 31, 1996. Based on amounts subsequently collected, the Company determined that portions of the allowance for doubtful accounts were no longer required and recognized income of $2,410,000 in 1998 and $1,642,000 in 1997. Any collections of the remaining $4,824,000 receivable will be recognized as income when received. In 1996, the Company negotiated a settlement of abandonment obligations with other joint owners of former oil properties in Gabon. As a result of this settlement, the Company recorded a net gain of $8,201,000 in 1996 to adjust for the dismantlement reserve no longer required. F-18

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) ENVIRONMENTAL MATTERS AND YEAR 2000 ISSUES - The Company's environmental and Year 2000 contingencies are reviewed in Management's Discussion and Analysis of Financial Condition and Results of Operations under the sections entitled "Environmental" and "Year 2000 Issues" on pages 15 through 17 of this Form 10-K report. OTHER MATTERS - The Company and its subsidiaries are engaged in a number of legal proceedings, all of which the Company considers routine and incidental to its business and none of which is considered material. In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide letters of credit that may be drawn upon if the Company fails to perform under those contracts. At December 31, 1998, the Company had contingent liabilities of $13,700,000 on outstanding letters of credit and $25,400,000 under certain financial guarantees. NOTE O - BUSINESS SEGMENTS Murphy's reportable segments are organized into two major types of business activities, each subdivided into geographic areas of operations. The Company's exploration and production activity is subdivided into segments for the United States, Canada, the United Kingdom, Ecuador, and all other countries; each of these segments derives revenues primarily from the sale of crude oil and natural gas. The refining, marketing and transportation segments in the United States and the United Kingdom derive revenues mainly from the sale of petroleum products; the Canadian segment derives revenues primarily from the transportation and trading of crude oil. The Company's management evaluates segment performance based on income from continuing operations, excluding interest income and interest expense. Intersegment transfers of crude oil and petroleum products are at market prices and intersegment services are recorded at cost. Information about business segments and geographic operations is reported in the following tables. Excise taxes on petroleum products of $831,385,000, $679,953,000 and $550,116,000 for the years 1998, 1997 and 1996, respectively, were excluded from revenues and costs and expenses. For geographic purposes, revenues are attributed to the country in which the sale occurs. The Company had no single customer from which it derived more than 10% of its revenues. Murphy's equity method investments are in companies that transport crude oil and petroleum products. Corporate and other activities, including interest income, miscellaneous gains (losses), interest expense and unallocated overhead, are shown in the tables to reconcile the business segments to consolidated totals. As used in the tables, "Certain Long-Lived Assets at December 31" exclude investments, noncurrent receivables and deferred tax assets. F-19

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) SEGMENT INFORMATION (CONTINUED ON PAGE F-21) EXPLORATION AND PRODUCTION -------------------------------------------------------------------- (MILLIONS OF DOLLARS) U.S. CANADA U.K. ECUADOR OTHER TOTAL ------ ------- -------- ---------- --------- -------- YEAR ENDED DECEMBER 31, 1998 Segment income (loss) $ .7 (7.5) (13.3) 4.8 (35.1) (50.4) Revenues from external customers 146.7 92.5 82.8 21.3 2.7 346.0 Intersegment revenues 32.4 42.5 12.3 -- -- 87.2 Interest income -- -- -- -- -- -- Interest expense, net of capitalization -- -- -- -- -- -- Income of equity companies -- -- -- -- -- -- Income tax expense (benefit) (.1) (11.3) (1.6) (.8) .1 (13.7) Significant noncash charges (credits) Depreciation, depletion, amortization 66.0 44.0 42.9 10.2 -- 163.1 Impairment of long-lived assets 29.9 10.1 24.3 -- 15.1 79.4 Provisions for major repairs -- 3.1 -- -- -- 3.1 Amortization of undeveloped leases 6.7 3.8 -- -- -- 10.5 Deferred and noncurrent income taxes (3.3) (6.3) (4.3) -- .7 (13.2) Additions to property, plant, equipment 104.0 94.1 67.5 10.2 .7 276.5 Total assets at year-end 399.1 595.6 317.6 60.3 13.3 1,385.9 - - ------------------------------------------------------------------------------------------------------------------------------------ YEAR ENDED DECEMBER 31, 1997 Segment income (loss) $ 51.6 19.0 16.3 14.5 (16.3) 85.1 Revenues from external customers 210.7 125.1 121.6 36.0 2.5 495.9 Intersegment revenues 64.1 60.5 -- -- -- 124.6 Interest income -- -- -- -- -- -- Interest expense, net of capitalization -- -- -- -- -- -- Income of equity companies -- -- -- -- -- -- Income tax expense (benefit) 27.2 9.8 15.4 (1.1) .1 51.4 Significant noncash charges (credits) Depreciation, depletion, amortization 79.4 37.9 43.7 11.4 -- 172.4 Impairment of long-lived assets 7.7 20.4 -- -- -- 28.1 Provisions for major repairs -- 4.6 -- -- -- 4.6 Amortization of undeveloped leases 6.7 3.6 .1 -- .1 10.5 Deferred and noncurrent income taxes (9.8) 9.1 (.9) -- 1.3 (.3) Additions to property, plant, equipment 102.5 135.1 80.0 10.4 10.9 338.9 Total assets at year-end 400.7 596.0 319.6 61.5 24.9 1,402.7 - - ------------------------------------------------------------------------------------------------------------------------------------ YEAR ENDED DECEMBER 31, 1996 Segment income (loss) $ 68.1 32.7 14.7 5.0 3.5 124.0 Revenues from external customers 193.4 65.0 96.6 35.0 8.8 398.8 Intersegment revenues 71.8 102.2 34.4 -- -- 208.4 Interest income -- -- -- -- -- -- Interest expense, net of capitalization -- -- -- -- -- -- Income of equity companies -- -- -- -- -- -- Income tax expense (benefit) 37.1 18.8 24.3 1.2 .4 81.8 Significant noncash charges (credits) Depreciation, depletion, amortization 60.5 30.8 40.8 8.9 6.6 147.6 Provisions for major repairs -- 4.4 -- -- -- 4.4 Amortization of undeveloped leases 6.5 3.0 .1 -- .1 9.7 Deferred and noncurrent income taxes 15.3 2.8 (3.4) -- (.7) 14.0 Additions to property, plant, equipment 149.8 91.6 55.9 11.7 4.5 313.5 Total assets at year-end 401.0 552.7 307.0 72.5 14.2 1,347.4 - - ------------------------------------------------------------------------------------------------------------------------------------ GEOGRAPHIC INFORMATION CERTAIN LONG-LIVED ASSETS AT DECEMBER 31 ------------------------------------------------------------------ (MILLIONS OF DOLLARS) U.S. CANADA U.K. ECUADOR OTHER TOTAL ----- ------ ----- ------- ----- ----- 1998 $ 706.2 600.4 352.8 54.4 8.4 1,722.2 1997 683.8 601.4 354.5 54.4 21.7 1,715.8 1996 668.1 560.1 331.7 55.4 12.1 1,627.4 F-20

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) SEGMENT INFORMATION (CONTINUED FROM PAGE F-20) REFINING, MARKETING & TRANSPORTATION ------------------------------------ CORP. & CONSOLI- (MILLIONS OF DOLLARS) U.S. U.K. CANADA TOTAL OTHER DATED ---- ---- ------ ----- ----- ----- YEAR ENDED DECEMBER 31, 1998 Segment income (loss) $ 27.7 17.3 2.5 47.5 (11.5) (14.4) Revenues from external customers 1,064.9 260.7 22.8 1,348.4 4.4 1,698.8 Intersegment revenues 3.1 -- .3 3.4 -- 90.6 Interest income -- -- -- -- 4.0 4.0 Interest expense, net of capitalization -- -- -- -- 10.5 10.5 Income of equity companies .8 -- -- .8 -- .8 Income tax expense (benefit) 15.7 7.9 3.1 26.7 (6.9) 6.1 Significant noncash charges (credits) Depreciation, depletion, amortization 29.3 5.2 1.9 36.4 3.2 202.7 Impairment of long-lived assets -- -- .7 .7 -- 80.1 Provisions for major repairs 15.2 2.0 -- 17.2 .1 20.4 Amortization of undeveloped leases -- -- -- -- -- 10.5 Deferred and noncurrent income taxes 2.9 .6 (.3) 3.2 9.1 (.9) Additions to property, plant, equipment 45.6 6.8 2.6 55.0 2.2 333.7 Total assets at year-end 465.5 160.8 50.2 676.5 102.0 2,164.4 - - ----------------------------------------------------------------------------------------------------------------- YEAR ENDED DECEMBER 31, 1997 Segment income (loss) $ 41.3 9.2 6.2 56.7 (9.4) 132.4 Revenues from external customers 1,342.8 268.6 26.1 1,637.5 4.4 2,137.8 Intersegment revenues 2.4 -- .1 2.5 -- 127.1 Interest income -- -- -- -- 4.8 4.8 Interest expense, net of capitalization -- -- -- -- .6 .6 Income of equity companies 1.1 -- -- 1.1 -- 1.1 Income tax expense (benefit) 23.7 5.9 6.2 35.8 (8.0) 79.2 Significant noncash charges (credits) Depreciation, depletion, amortization 27.8 4.7 2.0 34.5 2.5 209.4 Impairment of long-lived assets -- -- -- -- -- 28.1 Provisions for major repairs 18.1 1.8 -- 19.9 .1 24.6 Amortization of undeveloped leases -- -- -- -- -- 10.5 Deferred and noncurrent income taxes (.7) 1.9 .1 1.3 25.0 26.0 Additions to property, plant, equipment 29.2 3.7 4.6 37.5 7.3 383.7 Total assets at year-end 491.4 194.7 64.5 750.6 85.0 2,238.3 - - ----------------------------------------------------------------------------------------------------------------- YEAR ENDED DECEMBER 31, 1996 Segment income (loss) $ 1.8 6.2 6.1 14.1 (12.1) 126.0 Revenues from external customers 1,268.3 318.0 24.6 1,610.9 12.5 2,022.2 Intersegment revenues 2.5 -- .5 3.0 -- 211.4 Interest income -- -- -- -- 12.6 12.6 Interest expense, net of capitalization -- -- -- -- 2.9 2.9 Income of equity companies 1.3 -- -- 1.3 -- 1.3 Income tax expense (benefit) 1.3 3.4 5.8 10.5 (1.9) 90.4 Significant noncash charges (credits) Depreciation, depletion, amortization 26.5 3.8 1.6 31.9 2.9 182.4 Provisions for major repairs 19.1 1.2 -- 20.3 .1 24.8 Amortization of undeveloped leases -- -- -- -- -- 9.7 Deferred and noncurrent income taxes 2.6 3.5 -- 6.1 8.4 28.5 Additions to property, plant, equipment 21.0 13.5 8.4 42.9 1.1 357.5 Total assets at year-end 506.8 151.8 83.5 742.1 154.3 2,243.8 - - ----------------------------------------------------------------------------------------------------------------- GEOGRAPHIC INFORMATION REVENUES FROM EXTERNAL CUSTOMERS FOR THE YEAR ------------------------------------------------------ (MILLIONS OF DOLLARS) U.S. U.K. CANADA ECUADOR OTHER TOTAL ---- ---- ------- ------- ----- ----- 1998 $ 1,212.0 346.9 115.9 21.3 2.7 1,698.8 1997 1,554.7 392.9 151.7 36.0 2.5 2,137.8 1996 1,471.2 417.4 89.8 35.0 8.8 2,022.2 F-21

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) The following schedules are presented in accordance with SFAS No. 69, "Disclosures about Oil and Gas Producing Activities," to provide users with a common base for preparing estimates of future cash flows and comparing reserves among companies. Additional background information follows concerning four of the schedules. SCHEDULES 1 AND 2 - ESTIMATED NET PROVED OIL AND NATURAL GAS RESERVES - Reserves of crude oil, condensate, natural gas liquids and natural gas are estimated by the Company's engineers and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and judgmental decisions are required to estimate reserves. Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. The U.S. Securities and Exchange Commission defines proved reserves as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered as a result of additional investments for drilling new wells to offset productive units, recompleting existing wells, and/or installing facilities to collect and transport production. Production quantities shown are net volumes withdrawn from reservoirs. These may differ from sales quantities due to inventory changes, and especially in the case of natural gas, volumes consumed for fuel and/or shrinkage from extraction of natural gas liquids. Synthetic oil reserves in Canada are attributable to Murphy's share, after deducting estimated net profit royalty, of the Syncrude project, and include currently producing leases and the approved development of the Aurora mine. Additional reserves will be added as development progresses. The Company has no proved reserves attributable to either long-term supply agreements with foreign governments or investees accounted for by the equity method. SCHEDULE 4 - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES - Results of operations from exploration and production activities by geographic area are reported as if these activities were not part of an operation that also refines crude oil and sells refined products. Results of oil and gas producing activities include certain special items that are reviewed in Management's Discussion and Analysis of Financial Condition and Results of Operations on page 9 of this Form 10-K report, and should be considered in conjunction with the Company's overall performance. SCHEDULE 6 - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES - SFAS No. 69 requires calculation of future net cash flows using a 10% annual discount factor and year-end prices, costs and statutory tax rates, except for known future changes such as contracted prices and legislated tax rates. Future net cash flows from the Company's interest in synthetic oil are excluded. The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future cash flows because prices, costs and governmental policies do not remain static; appropriate discount rates may vary; and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts. Average crude oil prices used for this calculation at December 31, 1998, were $9.50 a barrel for the United States, $9.67 for Canadian light, $6.16 for Canadian heavy, $9.77 for Canadian offshore, $10.46 for the United Kingdom and $5.20 for Ecuador. Average natural gas prices were $2.06 an MCF for the United States, $1.65 for Canada and $2.18 for the United Kingdom. Oil prices declined sharply during 1998 and remain depressed in early 1999, while U.S. natural gas sales prices began a sharp decline in early 1999. Schedule 6 also presents the principal reasons for change in the standardized measure of discounted future net cash flows for each of the three years ended December 31, 1998. F-22

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued) SCHEDULE 1 - ESTIMATED NET PROVED OIL RESERVES CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS --------------------------------------------------------- SYNTHETIC UNITED UNITED OIL - (MILLIONS OF BARRELS) STATES CANADA* KINGDOM ECUADOR TOTAL CANADA TOTAL ------ ------ ------- ------- ----- ------ ----- PROVED December 31, 1995 24.6 36.3 40.0 29.6 130.5 96.2 226.7 Revisions of previous estimates .5 .6 .2 -- 1.3 3.2 4.5 Extensions and discoveries 4.0 3.8 14.6 -- 22.4 -- 22.4 Production (4.3) (5.2) (4.8) (2.2) (16.5) (3.0) (19.5) Sales (6.1) (.3) -- -- (6.4) -- (6.4) ---- ---- ---- ---- ----- ----- ----- December 31, 1996 18.7 35.2 50.0 27.4 131.3 96.4 227.7 Revisions of previous estimates 1.6 (.4) 6.1 6.6 13.9 10.5 24.4 Improved recovery -- .5 -- -- .5 -- .5 Purchases .2 2.1 -- -- 2.3 -- 2.3 Extensions and discoveries 2.5 18.8 6.2 -- 27.5 -- 27.5 Production (3.9) (5.8) (5.0) (2.9) (17.6) (3.4) (21.0) Sales -- (1.3) -- -- (1.3) -- (1.3) ---- ---- ---- ---- ----- ----- ----- December 31, 1997 19.1 49.1 57.3 31.1 156.6 103.5 260.1 Revisions of previous estimates (1.0) 6.7 5.0 2.6 13.3 15.9 29.2 Purchases -- 1.3 -- -- 1.3 -- 1.3 Extensions and discoveries 8.0 .3 -- 1.3 9.6 -- 9.6 Production (2.8) (6.5) (5.6) (2.8) (17.7) (3.8) (21.5) Sales (.3) (.1) -- -- (.4) -- (.4) ---- ---- ---- ---- ----- ----- ----- December 31, 1998 23.0 50.8 56.7 32.2 162.7 115.6 278.3 ==== ==== ==== ==== ===== ===== ===== PROVED DEVELOPED December 31, 1995 21.3 22.4 19.5 7.8 71.0 69.9 140.9 December 31, 1996 16.3 21.4 16.8 10.1 64.6 66.9 131.5 December 31, 1997 15.3 22.5 18.3 20.6 76.7 70.4 147.1 December 31, 1998 14.5 27.9 31.5 21.0 94.9 67.1 162.0 *Excludes 48.3 million barrels of crude oil to be added to reserves as development of the Hibernia and Terra Nova oil fields proceeds. SCHEDULE 2 - ESTIMATED NET PROVED NATURAL GAS RESERVES UNITED UNITED (BILLIONS OF CUBIC FEET) STATES CANADA KINGDOM SPAIN TOTAL ------ ------ ------- ----- ----- PROVED December 31, 1995 431.5 160.1 47.4 3.8 642.8 Revisions of previous estimates 19.8 (5.1) 2.1 (1.2) 15.6 Extensions and discoveries 85.0 15.6 -- -- 100.6 Production (58.3) (15.8) (5.6) (2.6) (82.3) Sales (13.6) (3.7) -- -- (17.3) ----- ----- ----- ----- ----- December 31, 1996 464.4 151.1 43.9 -- 659.4 Revisions of previous estimates (23.7) (4.9) (2.9) -- (31.5) Purchases 11.1 .4 -- -- 11.5 Extensions and discoveries 63.2 17.0 -- -- 80.2 Production (79.4) (16.4) (4.6) -- (100.4) Sales (.2) (6.8) -- -- (7.0) ----- ----- ----- ----- ----- December 31, 1997 435.4 140.4 36.4 -- 612.2 Revisions of previous estimates (14.3) (.2) 7.2 -- (7.3) Purchases -- 6.3 -- -- 6.3 Extensions and discoveries 80.9 2.6 -- -- 83.5 Production (61.9) (17.9) (4.5) -- (84.3) Sales -- (1.1) -- -- (1.1) ----- ----- ----- ----- ----- December 31, 1998 440.1 130.1 39.1 -- 609.3 ===== ===== ===== ===== ===== PROVED DEVELOPED December 31, 1995 229.0 150.0 27.6 3.8 410.4 December 31, 1996 291.1 146.0 25.4 -- 462.5 December 31, 1997 304.2 135.2 24.0 -- 463.4 December 31, 1998 291.8 120.3 29.9 -- 442.0 F-23

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued) SCHEDULE 3 - COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES SYNTHETIC UNITED UNITED OIL - (MILLIONS OF DOLLARS) STATES CANADA KINGDOM ECUADOR OTHER SUBTOTAL CANADA TOTAL ------ ------ ------- ------- ----- -------- ------ ----- YEAR ENDED DECEMBER 31, 1998 Property acquisition costs Unproved $ 14.1 2.7 .2 -- -- 17.0 -- 17.0 Proved 3.8 1.1 -- -- -- 4.9 -- 4.9 ----- ----- ----- ----- ----- ----- ----- ----- Total acquisition costs 17.9 3.8 .2 -- -- 21.9 -- 21.9 Exploration costs 77.6 18.3 2.6 -- 21.9 120.4 -- 120.4 Development costs 25.1 69.4 68.2 10.2 -- 172.9 16.4 189.3 ----- ----- ----- ----- ----- ----- ----- ----- Total capital expenditures 120.6 91.5 71.0 10.2 21.9 315.2 16.4 331.6 ----- ----- ----- ----- ----- ----- ----- ----- Charged to expense Dry hole expense 10.8 8.9 (.4) -- 12.2 31.5 -- 31.5 Geophysical and other costs 5.8 4.9 3.9 -- 9.0 23.6 -- 23.6 ----- ----- ----- ----- ----- ----- ----- ----- Total charged to expense 16.6 13.8 3.5 -- 21.2 55.1 -- 55.1 ----- ----- ----- ----- ----- ----- ----- ----- Expenditures capitalized $ 104.0 77.7 67.5 10.2 .7 260.1 16.4 276.5 ===== ===== ===== ===== ===== ===== ===== ===== YEAR ENDED DECEMBER 31, 1997 Property acquisition costs Unproved $ 20.5 5.9 .2 -- -- 26.6 -- 26.6 Proved 8.2 13.9 .1 -- -- 22.2 -- 22.2 ----- ----- ----- ----- ----- ----- ----- ----- Total acquisition costs 28.7 19.8 .3 -- -- 48.8 -- 48.8 Exploration costs 74.4 18.2 14.6 -- 28.1 135.3 -- 135.3 Development costs 43.9 96.0 76.0 10.4 -- 226.3 12.8 239.1 ----- ----- ----- ----- ----- ----- ----- ----- Total capital expenditures 147.0 134.0 90.9 10.4 28.1 410.4 12.8 423.2 ----- ----- ----- ----- ----- ----- ----- ----- Charged to expense Dry hole expense 30.9 4.5 5.7 -- 7.2 48.3 -- 48.3 Geophysical and other costs 13.6 7.2 5.2 -- 10.0 36.0 -- 36.0 ----- ----- ----- ----- ----- ----- ----- ----- Total charged to expense 44.5 11.7 10.9 -- 17.2 84.3 -- 84.3 ----- ----- ----- ----- ----- ----- ----- ----- Expenditures capitalized $ 102.5 122.3 80.0 10.4 10.9 326.1 12.8 338.9 ===== ===== ===== ===== ===== ===== ===== ===== YEAR ENDED DECEMBER 31, 1996 Property acquisition costs Unproved $ 16.9 5.7 -- -- -- 22.6 -- 22.6 Proved -- -- -- -- -- -- -- -- ----- ----- ----- ----- ----- ----- ----- ----- Total acquisition costs 16.9 5.7 -- -- -- 22.6 -- 22.6 Exploration costs 107.7 10.3 13.2 -- 8.9 140.1 -- 140.1 Development costs 60.1 75.7 56.1 11.7 -- 203.6 7.7 211.3 ----- ----- ----- ----- ----- ----- ----- ----- Total capital expenditures 184.7 91.7 69.3 11.7 8.9 366.3 7.7 374.0 ----- ----- ----- ----- ----- ----- ----- ----- Charged to expense Dry hole expense 17.3 1.7 9.5 -- -- 28.5 -- 28.5 Geophysical and other costs 17.6 6.1 3.9 -- 4.4 32.0 -- 32.0 ----- ----- ----- ----- ----- ----- ----- ----- Total charged to expense 34.9 7.8 13.4 -- 4.4 60.5 -- 60.5 ----- ----- ----- ----- ----- ----- ----- ----- Expenditures capitalized $ 149.8 83.9 55.9 11.7 4.5 305.8 7.7 313.5 ===== ===== ===== ===== ===== ===== ===== ===== F-24

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued) SCHEDULE 4 - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES SYNTHETIC UNITED UNITED OIL - (MILLIONS OF DOLLARS) STATES CANADA KINGDOM ECUADOR OTHER SUBTOTAL CANADA TOTAL ------ ------ ------- ------- ----- -------- ------ ----- YEAR ENDED DECEMBER 31, 1998 Revenues Crude oil and natural gas liquids Transfers to consolidated operations $ 32.4 7.1 12.3 -- -- 51.8 35.4 87.2 Sales to unaffiliated enterprises 3.2 48.3 58.0 19.1 -- 128.6 17.6 146.2 Natural gas 132.1 24.0 10.0 -- -- 166.1 -- 166.1 -------- ----- ----- ---- ----- ----- ----- ----- Total oil and gas revenues 167.7 79.4 80.3 19.1 -- 346.5 53.0 399.5 Other operating revenues/1/ 11.4 2.7 14.8 2.2 2.7 33.8 (.1) 33.7 -------- ----- ----- ---- ----- ----- ----- ----- Total revenues 179.1 82.1 95.1 21.3 2.7 380.3 52.9 433.2 -------- ----- ----- ---- ----- ----- ----- ----- Costs and expenses Production costs 43.6 34.3 35.7 7.0 -- 120.6 34.5 155.1 Exploration costs charged to expense 16.6 13.8 3.5 -- 21.2 55.1 -- 55.1 Undeveloped lease amortization 6.7 3.8 -- -- -- 10.5 -- 10.5 Depreciation, depletion and amortization 66.0 37.8 42.9 10.2 -- 156.9 6.2 163.1 Impairment of long-lived assets 29.9 10.1 24.3 -- 15.1 79.4 -- 79.4 Cancellation of a drilling rig contract -- 7.2 -- -- -- 7.2 -- 7.2 Selling and general expenses 15.7 6.0 3.6 .1 1.4 26.8 .1 26.9 -------- ----- ----- ---- ----- ----- ----- ----- Total costs and expenses 178.5 113.0 110.0 17.3 37.7 456.5 40.8 497.3 -------- ----- ----- ---- ----- ----- ----- ----- .6 (30.9) (14.9) 4.0 (35.0) (76.2) 12.1 (64.1) Income tax expense (benefit) (.1) (15.2) (1.6) (.8) .1 (17.6) 3.9 (13.7) -------- ----- ----- ---- ----- ----- ----- ----- Results of operations/2/ $ .7 (15.7) (13.3) 4.8 (35.1) (58.6) 8.2 (50.4) ======== ===== ===== ==== ===== ===== ===== ===== YEAR ENDED DECEMBER 31, 1997 Revenues Crude oil and natural gas liquids Transfers to consolidated operations $ 64.1 13.7 -- -- -- 77.8 46.8 124.6 Sales to unaffiliated enterprises 10.8 57.9 95.3 34.7 -- 198.7 21.1 219.8 Natural gas 196.7 22.1 12.2 -- -- 231.0 -- 231.0 -------- ----- ----- ---- ----- ----- ----- ----- Total oil and gas revenues 271.6 93.7 107.5 34.7 -- 507.5 67.9 575.4 Other operating revenues/3/ 3.2 24.0 14.1 1.3 2.5 45.1 -- 45.1 -------- ----- ----- ---- ----- ----- ----- ----- Total revenues 274.8 117.7 121.6 36.0 2.5 552.6 67.9 620.5 -------- ----- ----- ---- ----- ----- ----- ----- Costs and expenses Production costs 43.5 39.2 32.5 11.0 -- 126.2 38.6 164.8 Exploration costs charged to expense 44.5 11.7 10.9 -- 17.2 84.3 -- 84.3 Undeveloped lease amortization 6.7 3.6 .1 -- .1 10.5 -- 10.5 Depreciation, depletion and amortization 79.4 31.4 43.7 11.4 -- 165.9 6.5 172.4 Impairment of long-lived assets 7.7 20.4 -- -- -- 28.1 -- 28.1 Selling and general expenses 14.3 5.2 2.7 .2 1.4 23.8 .1 23.9 -------- ----- ----- ---- ----- ----- ----- ----- Total costs and expenses 196.1 111.5 89.9 22.6 18.7 438.8 45.2 484.0 -------- ----- ----- ---- ----- ----- ----- ----- 78.7 6.2 31.7 13.4 (16.2) 113.8 22.7 136.5 Income tax expense (benefit) 27.2 1.4 15.4 (1.1) .1 43.0 8.4 51.4 -------- ----- ----- ---- ----- ----- ----- ----- Results of operations/2/ $ 51.5 4.8 16.3 14.5 (16.3) 70.8 14.3 85.1 ======== ===== ===== ==== ===== ===== ===== ===== /1/ Includes pretax gains of $4 from modification of a U.K. long-term sales contract and $2.4 from recovery on a 1996 contract modification in Ecuador. /2/ Excludes corporate overhead and interest. /3/ Includes pretax gains of $20.7 from sale of Canadian properties and $1.6 from recovery on a 1996 contract modification in Ecuador. F-25

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued) SCHEDULE 4 - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (CONTINUED) SYNTHETIC UNITED UNITED OIL - (MILLIONS OF DOLLARS) STATES CANADA KINGDOM ECUADOR OTHER SUBTOTAL CANADA TOTAL ------ ------ ------- ------- ----- -------- ------ ----- YEAR ENDED DECEMBER 31, 1996 Revenues Crude oil and natural gas liquids Transfers to consolidated operations $ 71.8 57.6 34.4 -- -- 163.8 44.6 208.4 Sales to unaffiliated enterprises 14.3 24.0 67.7 35.0 -- 141.0 18.7 159.7 Natural gas 147.1 17.3 14.4 -- 7.8 186.6 -- 186.6 -------- ----- ----- ---- ----- ----- ----- ----- Total oil and gas revenues 233.2 98.9 116.5 35.0 7.8 491.4 63.3 554.7 Other operating revenues/1/ 32.0 5.0 14.5 -- 1.0 52.5 -- 52.5 -------- ----- ----- ---- ----- ----- ----- ----- Total revenues 265.2 103.9 131.0 35.0 8.8 543.9 63.3 607.2 -------- ----- ----- ---- ----- ----- ----- ----- Costs and expenses Production costs 45.4 30.8 34.7 10.9 .7 122.5 38.0 160.5 Exploration costs charged to expense 34.9 7.8 13.4 -- 4.4 60.5 -- 60.5 Undeveloped lease amortization 6.5 3.0 .1 -- .1 9.7 -- 9.7 Depreciation, depletion and amortization 60.5 25.2 40.8 8.9 6.6 142.0 5.6 147.6 Selling and general expenses 12.7 5.2 3.0 .2 1.3 22.4 .1 22.5 Loss from modifications to foreign crude oil contracts -- -- -- 8.8 (8.2) .6 -- .6 -------- ----- ----- ---- ----- ----- ----- ----- Total costs and expenses 160.0 72.0 92.0 28.8 4.9 357.7 43.7 401.4 -------- ----- ----- ---- ----- ----- ----- ----- 105.2 31.9 39.0 6.2 3.9 186.2 19.6 205.8 Income tax expense 37.1 11.3 24.3 1.2 .4 74.3 7.5 81.8 -------- ----- ----- ---- ----- ----- ----- ----- Results of operations/2/ $ 68.1 20.6 14.7 5.0 3.5 111.9 12.1 124.0 ======== ===== ===== ==== ===== ===== ===== ===== /1/ Includes pretax gain of $27.9 on sale of U.S. onshore properties. /2/ Excludes corporate overhead and interest. SCHEDULE 5 - CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES SYNTHETIC UNITED UNITED OIL - (MILLIONS OF DOLLARS) STATES CANADA KINGDOM ECUADOR OTHER SUBTOTAL CANADA TOTAL ------ ------ ------- ------- ----- -------- ------ ----- DECEMBER 31, 1998 Unproved oil and gas properties $ 102.4 31.8 1.3 -- 20.3 155.8 -- 155.8 Proved oil and gas properties 1,536.1 755.5/1/ 836.0 199.5 -- 3,327.1 140.8 3,467.9 --------- ------ ------ ------ ----- -------- ----- -------- Gross capitalized costs 1,638.5 787.3 837.3 199.5 20.3 3,482.9 140.8 3,623.7 Accumulated depreciation, depletion and amortization Unproved oil and gas properties (50.7) (18.2) (1.0) -- (19.1) (89.0) -- (89.0) Proved oil and gas properties/2/ (1,250.4) (317.8)/1/ (585.6) (145.1) -- (2,298.9) (23.1) (2,322.0) --------- ------ ------ ------ ----- -------- ----- -------- Net capitalized costs $ 337.4 451.3 250.7 54.4 1.2 1,095.0 117.7 1,212.7 ========= ====== ====== ====== ===== ======== ===== ======== DECEMBER 31, 1997 Unproved oil and gas properties $ 96.8 32.9 4.3 -- 19.6 153.6 -- 153.6 Proved oil and gas properties 1,468.9 732.9/1/ 764.5 189.3 -- 3,155.6 133.6 3,289.2 --------- ------ ------ ------ ----- -------- ----- -------- Gross capitalized costs 1,565.7 765.8 768.8 189.3 19.6 3,309.2 133.6 3,442.8 Accumulated depreciation, depletion and amortization Unproved oil and gas properties (47.0) (18.2) (1.0) -- (4.0) (70.2) -- (70.2) Proved oil and gas properties/2/ (1,185.6) (295.0)/1/ (520.0) (134.9) -- (2,135.5) (18.8) (2,154.3) --------- ------ ------ ------ ----- -------- ----- -------- Net capitalized costs $ 333.1 452.6 247.8 54.4 15.6 1,103.5 114.8 1,218.3 ========= ====== ====== ====== ===== ======== ===== ======== /1/ Includes net costs of $276.3 in 1998 and $249 in 1997 related to the Hibernia and Terra Nova oil fields. /2/ Does not include reserve for dismantlement costs of $154.7 in 1998 and $153 in 1997. F-26

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued) SCHEDULE 6 - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES/1/ UNITED UNITED (MILLIONS OF DOLLARS) STATES CANADA/2/ KINGDOM ECUADOR TOTAL ------ --------- ------- ------- ----- DECEMBER 31, 1998 Future cash inflows $ 1,120.5 647.6 667.2 167.2 2,602.5 Future development costs (182.7) (177.5) (64.6) (14.9) (439.7) Future production and abandonment costs (361.1) (269.9) (372.6) (93.9) (1,097.5) Future income taxes (139.0) (28.3) (23.6) (.6) (191.5) --------- ------ ------ ------ -------- Future net cash flows 437.7 171.9 206.4 57.8 873.8 10% annual discount for estimated timing of cash flows (138.1) (74.3) (56.4) (23.1) (291.9) --------- ------ ------ ------ -------- Standardized measure of discounted future net cash flows $ 299.6 97.6 150.0 34.7 581.9 ========= ====== ====== ====== ======== DECEMBER 31, 1997 Future cash inflows $ 1,487.7 769.6 972.0 366.3 3,595.6 Future development costs (154.6) (253.1) (104.2) (49.7) (561.6) Future production and abandonment costs (348.5) (296.3) (356.3) (111.4) (1,112.5) Future income taxes (286.0) (6.8) (145.7) (26.7) (465.2) --------- ------ ------ ------ -------- Future net cash flows 698.6 213.4 365.8 178.5 1,456.3 10% annual discount for estimated timing of cash flows (214.7) (115.2) (104.0) (59.4) (493.3) --------- ------ ------ ------ -------- Standardized measure of discounted future net cash flows $ 483.9 98.2 261.8 119.1 963.0 ========= ====== ====== ====== ======== /1/Excludes future net cash flows from synthetic oil of $64.1 at December 31, 1998, and $461.5 at December 31, 1997. /2/Excludes future net cash flows attributable to 48.3 million barrels of crude oil to be added to reserves as development of the Hibernia and Terra Nova oil fields proceeds. Following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown. (MILLIONS OF DOLLARS) 1998 1997 1996 ---- ---- ---- Net changes in prices, production costs and development costs $ (894.8) (1,437.3) 643.2 Sales and transfers of oil and gas produced, net of production costs (132.3) (230.8) (324.9) Net change due to extensions and discoveries 125.4 278.6 450.8 Net change due to purchases and sales of proved reserves 4.5 17.4 (121.4) Development costs incurred 165.4 214.2 201.5 Accretion of discount 129.0 217.6 115.6 Revisions of previous quantity estimates 30.7 55.0 54.8 Net change in income taxes 191.0 327.3 (352.2) -------- -------- ------- Net increase (decrease) (381.1) (558.0) 667.4 Standardized measure at January 1 963.0 1,521.0 853.6 -------- -------- ------- Standardized measure at December 31 $ 581.9 963.0 1,521.0 ======== ======== ======= F-27

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED) FIRST SECOND THIRD FOURTH (MILLIONS OF DOLLARS EXCEPT PER SHARE AMOUNTS) QUARTER QUARTER QUARTER QUARTER YEAR ------- ------- ------- ------- ---- YEAR ENDED DECEMBER 31, 1998/1/ Sales and other operating revenues/2/ $ 439.8 447.8 432.2 374.7 1,694.5 Income (loss) before income taxes 24.8 36.9 15.4 (85.4) (8.3) Net income (loss) 15.5 22.2 9.0 (61.1) (14.4) Net income (loss) per Common share - basic .35 .49 .20 (1.36) (.32) Net income (loss) per Common share - diluted .35 .49 .20 (1.36) (.32) Cash dividends per Common share .35 .35 .35 .35 1.40 Market Price/3/ High 54 7/16 53 11/16 51 15/16 42 5/16 54 7/16 Low 47 7/16 48 1/8 34 1/2 36 3/16 34 1/2 YEAR ENDED DECEMBER 31, 1997/1/ Sales and other operating revenues/2/ $ 507.4 506.7 555.5 563.8 2,133.4 Income before income taxes 53.4 42.8 64.3 51.2 211.7 Net income 30.6 27.6 42.3 31.9 132.4 Net income per Common share - basic .68 .62 .94 .71 2.95 Net income per Common share - diluted .68 .61 .94 .71 2.94 Cash dividends per Common share .325 .325 .35 .35 1.35 Market Price/3/ High 54 1/4 49 1/4 58 13/16 62 9/16 62 9/16 Low 46 43 48 3/4 53 5/16 43 /1/The effects of special gains (losses) on quarterly net income are reviewed in Management's Discussion and Analysis of Financial Condition and Results of Operations on pages 12 and 13 of this Form 10-K report. Quarterly totals, in millions of dollars, and the effect per Common share of these special items are shown in the following table. First Second Third Fourth Quarter Quarter Quarter Quarter Year 1998 ---- Quarterly totals $ -- 4.2 -- (62.1) (57.9) Per Common share - basic -- .09 -- (1.38) (1.29) Per Common share - diluted -- .09 -- (1.38) (1.29) 1997 ---- Quarterly totals -- -- (.1) .2 .1 Per Common share - basic -- -- -- -- -- Per Common share - diluted -- -- -- -- -- /2/Amounts for 1997 and the first three quarters of 1998 have been restated to conform to presentation for the year ended December 31, 1998. /3/Market prices of Common Stock are as quoted on the New York Stock Exchange. F-28

EXHIBIT 13 1998 ANNUAL REPORT TO SECURITY HOLDERS CONTENTS Murphy Oil at a Glance 1 Highlights 3 Letter to the Shareholders 4 Exploration and Production 6 Refining, Marketing & Transportation 16 Corporate Responsibility 20 Statistical Summary 21 Directors and Officers 23 Principal Subsidiaries 24 1998 Form 10-K Report follows page 24 Financial Statements and Supplemental Data F-1 Corporate Information (inside back cover) 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's interest percentage in exploration and production projects and other jointly owned facilities is shown following the name of each field, block or facility.

MURPHY OIL AT A GLANCE Murphy Oil Corporation is a worldwide oil and gas exploration and production company with refining and marketing operations in the United States and the United Kingdom. Throughout its history, the Company has earned a reputation for conservative financial management, good strategic decisions, and the ability to steer a steady course in the wake of fluctuating commodity prices and industry uncertainty. Never were these strengths more necessary than in 1998, when Murphy - - -- along with the rest of the oil and gas industry -- endured a slump in oil prices that adversely affected its financial performance throughout the year. Operationally, it was a different story. For the eighth consecutive year, proved reserves grew. The Company's production profile, already one of the strongest in the industry, strengthened as several new oil fields came on stream that provide long production lives at a low cost. Discoveries in deepwater Gulf of Mexico, where the Company's early entry has given it a major presence, and onshore Louisiana highlighted the year's domestic exploration efforts. Murphy's taste for exposure to significant growth offered by international frontier exploration was reinforced in 1998 by acquisition of acreage offshore Malaysia. [GRAPH - INCOME CONTRIBUTION FROM CONTINUING OPERATIONS BY FUNCTION] [GRAPH - ESTIMATED NET PROVED HYDROCARBON RESERVES] 1

Downstream operations continued to reduce operating costs while increasing operational efficiency and reliability. Notable in 1998 was the success of Murphy's marketing expansion in collaboration with Wal-Mart. Murphy has built 35 stations in Wal-Mart parking areas, giving the Company a leading position in a unique niche in the U.S. marketplace; further expansion is planned in 1999. Costs for the initiative are in line with projections, while volume is exceeding expectations. Murphy's U.K. refining and marketing efforts recorded another profitable year in 1998. The Company's commitment to and investment in employee safety, environmental stewardship and corporate responsibility resulted in yet another year of achievement well above industry norms. All in all, 1998 will be remembered as much for accomplishments -- growth in proved reserves, increasing oil production, significant discoveries and the success of the Wal-Mart marketing initiative -- as for the challenges of low commodity prices. As the Company looks forward to 1999 and beyond, the key elements are in place -- quality oil properties; growing production; a focused, robust exploration portfolio; and a strong balance sheet -- to enable the Company to rebound from 1998 stronger, bigger and more profitable than before. [GRAPH - CASH FLOW FROM CONTINUING OPERATIONS BY FUNCTION] [GRAPH - CAPITAL EXPENDITURES BY FUNCTION] 2

HIGHLIGHTS - - ------------------------------------------------------------------------------------------------------------------ FINANCIAL - - -------------------------------------------------------------------------------------------------------- (Thousands of dollars except per share data) 1998 1997 1996 - - -------------------------------------------------------------------------------------------------------- FOR THE YEAR* - - -------------------------------------------------------------------------------------------------------- Revenues $ 1,698,848 2,137,767 2,022,176 Income (loss) from continuing operations (14,394) 132,406 125,956 Net income (loss) (14,394) 132,406 137,855 Cash dividends paid 62,939 60,573 58,294 Capital expenditures for continuing operations 388,799 468,031 418,056 Net cash provided by continuing operations 321,091 401,843 472,480 Average Common shares outstanding - diluted 44,955,679 44,960,907 44,904,636 - - -------------------------------------------------------------------------------------------------------- AT END OF YEAR - - -------------------------------------------------------------------------------------------------------- Working capital $ 56,616 48,333 56,128 Total assets 2,164,419 2,238,319 2,243,786 Notes payable 189,705 28,367 20,871 Nonrecourse debt of a subsidiary 143,768 177,486 180,957 Stockholders' equity 978,233 1,079,351 1,027,478 - - -------------------------------------------------------------------------------------------------------- PER SHARE OF COMMON STOCK* - - -------------------------------------------------------------------------------------------------------- Income (loss) from continuing operations - diluted $ (.32) 2.94 2.80 Net income (loss) - diluted (.32) 2.94 3.07 Cash dividends paid 1.40 1.35 1.30 Stockholders' equity 21.76 24.04 22.90 - - -------------------------------------------------------------------------------------------------------- *Includes special items that are detailed in Management's Discussion and Analysis, page 9 of the attached Form 10-K report. OPERATING - - -------------------------------------------------------------------------------------------------------- 1998 1997 1996 - - -------------------------------------------------------------------------------------------------------- NET CRUDE OIL AND GAS LIQUIDS PRODUCED - BARRELS A DAY 59,128 57,494 53,210 United States 7,798 10,760 11,645 International 51,330 46,734 41,565 NET NATURAL GAS SOLD - THOUSANDS OF CUBIC FEET A DAY 230,901 268,669 220,633 United States 169,519 211,207 155,017 International 61,382 57,462 65,616 CRUDE OIL REFINED - BARRELS A DAY 165,580 161,560 157,886 United States 134,800 134,854 126,586 United Kingdom 30,780 26,706 31,300 PETROLEUM PRODUCTS SOLD - BARRELS A DAY 174,152 163,430 161,459 United States 137,620 134,209 127,590 United Kingdom 36,093 28,977 33,615 Canada 439 244 254 - - -------------------------------------------------------------------------------------------------------- 3

LETTER TO THE SHAREHOLDERS [PHOTOGRAPH APPEARS HERE] DEAR FELLOW SHAREHOLDER: Like most other oil and gas companies, Murphy Oil Corporation's bottom line was adversely affected in 1998 by low commodity prices, which began to fall in the fourth quarter of 1997 and continued to slide throughout 1998. As a result, I must report to you that your Company's earnings before special items in 1998 were down 67% to $43.5 million ($.97 a share), and after special items, primarily a $57.6 million after-tax write-down of the carrying value of oil and gas assets, we experienced a net loss of $14.4 million ($.32 a share). A word about the write-down. It is absolutely necessary that the value of our assets reflect the world as it actually exists. The unavoidable fact is that crude oil prices were lower on December 31, 1998, in nominal terms, than at any year-end since 1973 and in real terms than at any year-end since 1931. Clearly, this influenced our price outlook and caused us to reevaluate forward assumptions, triggering the write-down. Significantly, none of Murphy's core properties -- Hibernia, Terra Nova, Syncrude, Schiehallion and Mungo/Monan -- were impaired. There is no escaping the fact that economic troubles, almost exclusively outside the United States and particularly in Asian markets, caused a marked slowdown in energy growth leading to a significant drop in crude oil prices. Asia alone went from adding 750,000 barrels a day of demand in 1997 to dropping a like amount in 1998. This swing of 1.5 million barrels a day, coupled with Iraq's renewed crude oil sales, sent markets tumbling into one of their periodic tailspins. All companies in this remarkably competitive business are going to be telling their shareholders about reductions in capital spending, cost-cutting measures and a reduced bottom line. In that regard, Murphy is no different. But I can also tell you that your Company's proven, disciplined approach to financial management, which has sustained us through bad times and guided us during boom years, helped cushion the blows in 1998 and gives us important advantages as we look ahead to 1999 and beyond. In fact, I believe our Company established a platform in 1998 from which we will profitably grow for many years. Let's review the past year. *During 1998, two low-cost U.K. oil fields, Mungo/Monan and Schiehallion, started up. In Canada, the Hibernia oil field was on stream for its first full year and will hit plateau production rates this year. Cash lifting costs at plateau are now projected at around $2.00 a barrel. Syncrude set a new production record of 210,000 barrels a day and reduced cash lifting cost to a record low of $8.99 a barrel. Overall, as new lower-cost fields are added to our mix, costs are driven down even more. Cash lifting costs across all of Murphy's barrels are estimated to be $4.10 a barrel in 1999, $3.54 a barrel if [GRAPH - HYDROCARBON PRODUCTION REPLACEMENT] 4

Syncrude (a mining operation) is excluded, compared to $4.35 in 1998 ($3.79 excluding Syncrude), and are the lowest in six years. Production should average 107,000 equivalent barrels a day in 1999, a Company record. *Exploration results in 1998 were excellent. Onshore South Louisiana, we extended the N.E. Wright field with the Guidry No. 1 well, penetrating 150 feet of pay in four sands. A likely 50 billion cubic feet (BCF) of natural gas reserves were proved up and another potentially equal sized offset spuds in the second quarter. Gulf of Mexico shelf results reflect hitting on 14 of 16 wells. While no single shelf discovery made an impact, collectively these reserve additions will maintain our 1999 U.S. natural gas production at 1998 levels. Deepwater exploration in the Gulf of Mexico kicked off in 1998. Four wells were drilled and two, the last two, were discoveries. Boomslang, in Ewing Bank Block 994, encountered 185 feet of pay, and importantly, sets up a much larger prospect called Sidewinder in the cornering block. The North Marlin wildcat on Viosca Knoll Block 827 found reserves of around 100 BCF and has an offset with the same potential that spuds in the third quarter of 1999. Most importantly, the Habanero wildcat in Garden Banks Block 341 penetrated over 200 feet of excellent reservoir rock to provide Murphy's third consecutive, and first marquee, deepwater discovery. A separate and potentially larger prospect named Moccasin, at Garden Banks Block 253, will be drilled later this year. Success at Habanero lowers the risk at Moccasin. *Murphy Oil Corporation added 53 million equivalent barrels of reserves in 1998 and ended the year with 380 million equivalent barrels of proved reserves, the highest in the Company's history, and the eighth consecutive year for an increase. *Murphy's downstream business expanded its arrangement with Wal-Mart as 1998 ended. I fully expect that over 100 sites will be in operation before the end of 1999, up from 35 today. The capital cost per unit is extraordinarily low because no real estate is purchased nor is a convenience store built. In addition, volumes are much higher than traditional SPUR stations, resulting in quite low operating costs, and most importantly, a competitive advantage. I am proud of what was accomplished in 1998 although the near depression level conditions existing in our industry at year-end masked our successes. In 1999, we will control those areas within our grasp -- production volume and cost, as well as capital spending. In addition, we will continue to search for opportunities. Cash-strapped companies are facing difficult choices and asset sales will likely result. On the plus side, world oil demand climbed in 1998 despite the Asian meltdown and is forecast to increase by 1.1 million barrels a day in 1999. This increase, when coupled with high-cost production shut-ins and the significant reduction in new investment, means recovery is under way. Our Company will work out of this, and Murphy Oil Corporation will be a leaner, more efficient and much, much stronger company on the other side. I appreciate your patience and predict it will be rewarded. /s/ Claiborne P. Deming Claiborne P. Deming President and Chief Executive Officer March 1, 1999 El Dorado, Arkansas 5

EXPLORATION AND PRODUCTION THE YEAR IN REVIEW A successful exploration program, a full year of production from the Hibernia oil field (6.5%) offshore eastern Canada, and commencement of production from two new fields in the United Kingdom highlighted 1998 exploration and production activity. Economic woes that began in Asia, spread to Latin America and suppressed the demand for crude oil worldwide contributed to a significant decline in crude oil prices during the year. However, Murphy's exploration and production team managed to stay focused by growing the Company with the drill bit and improving an already impressive production profile, and by making significant additions to its international frontier exploration acreage. Earnings from the Company's exploration and production activities, before special items, totaled $5.8 million in 1998. Proved reserves at the end of 1998 increased to 380 million barrels of oil equivalent, marking the eighth consecutive year that Murphy has more than replaced its hydrocarbon production. Although worldwide production of 97,612 barrels of oil equivalent a day represented a reduction of approximately 5% from 1997's record levels, crude oil production increased 3%. Expectations for an overall 10% increase in 1999 should once again propel the Company into record territory. Murphy's core operating areas include four of the world's premier, politically secure oil and natural gas basins: the Gulf of Mexico, the Jeanne d'Arc basin off the east coast of Canada, western Canada and the United Kingdom. Over 65% of Murphy's exploration capital was invested in the Gulf of Mexico and onshore South Louisiana in 1998, and a similar allocation is anticipated for 1999. In addition to its established production base on the Gulf of Mexico continental shelf, Murphy has amassed a significant leasehold acreage position in the burgeoning, and ever more important, deepwater play. The year 1998 proved to be a breakthrough year, as the Company made its first deepwater discoveries. [GRAPH - NET HYDROCARBONS PRODUCED] 6

Offshore eastern Canada in the Jeanne d'Arc basin, the Hibernia field produced at an average gross rate of 65,000 barrels a day. Planned plateau production of 135,000 barrels a day is expected to be achieved in 1999. Elsewhere in the basin, the Terra Nova oil development project (12%) remains on schedule to deliver first oil, within budget, before the end of the year 2000. Construction and fabrication of the floating production system commenced in 1998. Terra Nova is currently expected to achieve gross peak production of 115,000 barrels of crude oil a day. Murphy's Canadian activities also include an interest in Syncrude (5%), the world's largest producer of synthetic crude oil from oil sands. This light, sweet crude oil could eventually provide half of Canada's crude oil production. EXPLORATION AND PRODUCTION - - ---------------------------------------------------------------------------- (Thousands of dollars) 1998 1997 - - ---------------------------------------------------------------------------- Income contribution* $ 5,809 84,984 Total assets 1,385,879 1,402,684 Capital expenditures 331,647 423,181 - - ---------------------------------------------------------------------------- Crude oil and liquids produced - barrels a day 59,128 57,494 Natural gas sold - MCF a day 230,901 268,669 Net proved hydrocarbon reserves - thousands of oil equivalent barrels 379,900 362,100 - - ---------------------------------------------------------------------------- *Before special items Since the discovery of the giant Ninian field in the early 1970s, the United Kingdom has been an integral part of Murphy's portfolio. Production from the Schiehallion (5.9%) and Mungo/Monan (12.7%) fields came on stream during the third quarter of 1998 and provides the catalyst for what is expected to be a 45% increase in the Company's oil production from the area. [PHOTOGRAPH APPEARS HERE] 7

Although Murphy's exploration programs emphasize those areas where significant production has been established, the Company also possesses the technical expertise to identify frontier prospects, along with the resources to acquire significant ownership positions therein. Utilizing that ownership position to fund exploratory drilling has been an available option that will continue to be implemented when warranted. Frontier areas of particular note include the U.K. Atlantic Margin, Philippines, Pakistan, Alaska, and most recently, Malaysia, where production sharing contracts covering three offshore blocks were recently signed. Murphy has been well served by its strategy to use long-lived, low-cost oil properties in secure, established basins around the world to fund an active, yet focused, exploration program that seeks meaningful growth opportunities. Coupled with the Company's conservative financial practices, this strategy has put Murphy in a position, both operationally and financially, to use the exploration and production side of its business as its primary growth vehicle. A review of the Company's principal exploration and production activities is presented in the sections that follow. Unless otherwise indicated, average daily production rates are net to the Company after deduction for royalty interests. The terms crude oil production and oil production include natural gas liquids where applicable. Murphy's U.S. operations are concentrated in the Gulf of Mexico region and onshore South Louisiana. The Company participated in 20 exploratory wells during 1998, 17 of which were successful, for an 85% success ratio. Additions to the Company's U.S. proved reserves totaled 107 billion cubic feet of natural gas [GULF OF MEXICO MAP] 8

equivalents in 1998, which amounted to 136% of U.S. hydrocarbon production. Murphy upgraded its leasehold position in the Gulf by participating in two 1998 federal lease sales, acquiring interests ranging from 33% to 100% in 21 blocks, 15 of which are in deep water, where the Company now has an interest in 97 leases. The DEEPWATER GULF OF MEXICO continues to offer the potential for impact reserves in areas where infrastructure is growing. Murphy intends to dedicate a larger percentage of exploratory drilling capital to this play. Discoveries at Ewing Bank Block 994 (Boomslang, 45%) and at Viosca Knoll Block 827 (North Marlin, 30%) highlighted 1998 activity. The Boomslang well, located in approximately 850 feet of water, penetrated 185 feet of net oil pay and enhanced the prospects located on five adjacent blocks in which Murphy has a working interest of 42.5%. The North Marlin well encountered a hydrocarbon-bearing interval similar to the predominantly natural gas reservoirs in the Company's nearby Tahoe field (30%). Water depth at North Marlin exceeds 2,500 feet. Both of these areas contain significant additional reserve potential that will be explored over the next 18 months. Two additional deepwater wildcats spudded in the fourth quarter of 1998, one in the "Auger" basin at Garden Banks Block 341 (Habanero, 33.8%) and one in the "Enchilada" basin at Garden Banks Block 168 (Wadden Zee, 33.3%). In early 1999, it was announced that the Habanero well, located in approximately 2,000 feet of water, had encountered over 200 feet of net oil pay in two zones. Evaluation work to determine the extent of this discovery continues. Although the drop in oil and natural gas prices will curtail exploration activity, Murphy remains active on the GULF OF MEXICO OUTER CONTINENTAL SHELF. Positive drilling outcomes resulted in 14 successful wells, all of which will be on stream by the end of 1999. Initial gross production from the larger discoveries at Vermilion Block 130 (75%), Ship Shoal Block 59 (50%), South Pelto Block 18 (25%), Matagorda Island Block 565 (40%), Vermilion Block 335 (35%) and East Cameron Block 38 (33.3%) will total approximately 57 million cubic feet of natural gas a day. [PHOTOGRAPH APPEARS HERE] 9

The Destin Dome Block 56 unit (33.3%) is one of the largest undeveloped natural gas discoveries remaining in the United States. Located in federal waters 30 miles off the coast of Florida, three previously drilled exploratory wells have confirmed a significant reservoir of dry natural gas in the Norphlet sandstone. Murphy and its two partners filed a development plan with the U.S. Minerals Management Service in November 1996. A rigorous regulatory process designed to protect the environment and ensure compatibility with other uses of surrounding areas is under way. Completion of the regulatory review process could extend into late 1999. ONSHORE SOUTH LOUISIANA, a significant natural gas discovery at the N.E. Wright field (50%) is currently producing, through temporary facilities, at a gross rate of approximately 10 million cubic feet a day. The well logged 150 feet of net natural gas pay in four sands and confirmed a large structure underlying the field. Delineation drilling is slated for 1999 to determine the magnitude of the discovery and the development plan. CANADA continues to be Murphy's largest source of crude oil reserves and production and set a production record of 28,199 barrels a day in 1998. An increasing proportion of this supply (57% in the fourth quarter of 1998) is provided by premium properties, namely the Hibernia field and Syncrude. With the Terra Nova field to follow, Murphy can look forward to long-lived, stable volumes of profitable production, augmenting its large resource base in the more traditional areas of western Canada, where the Company set a record of 49 million cubic feet a day of natural gas production in 1998. [GRAPH - CAPITAL EXPENDITURES--EXPLORATION AND PRODUCTION] [PHOTOGRAPH APPEARS HERE] 10

Murphy enjoyed its first full year of production in the Jeanne d'Arc basin off the EAST COAST OF CANADA following start-up of the Hibernia field in late 1997. Early performance exceeded expectations, resulting in production curtailment while awaiting placement of water and gas injection wells. Later in 1998, mechanical problems with the first gas injection well necessitated additional curtailment for conservation of produced gas. A second gas injector was completed in early 1999. Despite these temporary reservoir management issues, the field produced 23.9 million barrels during the year, or 4,192 barrels a day net to Murphy, exceeding budget expectations. More importantly, performance data collected during the year increased confidence in the capability of the reservoir and platform. As a result, 1999 performance is expected to continue to exceed Murphy's original projections, in terms of both higher production and lower operating cost per unit. The Hibernia reservoir is the source of current production from the field and accounts for 485 million barrels of the 615 million barrels of reserves projected to be recovered from the field. The remaining oil is contained within the Avalon reservoir, which also offers new exploratory opportunities that have been identified and are being considered. Such efforts have the potential to add significant new reserves and to maintain plateau production levels well into the next decade. Development of the Terra Nova oil field was approved in early 1998. Key components, including the production vessel, turret and topsides, are under construction and include debottlenecking of the facility from a design capacity of 125,000 to 150,000 barrels a day. This will accelerate production of the 300 to 400 million barrels estimated to be recoverable from the field. First oil is anticipated near the end of the year 2000. Murphy earned a 20% interest in additional acreage off Canada's east coast in 1998 by joining in the drilling of an exploratory well on the Scotian Shelf in a region close to the Sable Island producing area. Although the initial well was unsuccessful, further evaluation of this acreage position, along with an existing parcel in the Jeanne d'Arc basin at Cape Race (25%), should yield additional exploration prospects in future years. [GRAPH - WORLDWIDE EXTRACTION COSTS] 11

[WESTERN CANADA MAP] Murphy has been active in WESTERN CANADA for many years. By late 1998, supply and demand for Canadian natural gas became much more balanced as a result of pipeline expansions, and prices rose accordingly. In anticipation of this, Murphy's exploration effort in western Canada has been directed toward natural gas in northern Alberta and British Columbia. Successful delineation of the 1997 discovery at Josephine (50-63%) and drilling successes at Cranberry (100%) and Birley (50%) contributed to the Company's record Canadian gas production in 1998. Exploration and development activities will continue in 1999, and further increases in natural gas deliverability are anticipated. In early 1998, Murphy responded quickly to low prices for heavy crude oil by significantly curtailing heavy oil production. Higher cost wells were shut in and thermal pilot programs were suspended. Similar reactions throughout the industry reduced availability of heavy crude oil and led to modest price improvements, allowing some production to be reactivated later in 1998. The Company's light oil portfolio in western Canada is mature and continues to be managed with a "harvesting" mentality. SYNCRUDE, Canada's largest source of crude oil production, combines mining, extraction and upgrading technologies to produce a light, sweet synthetic crude product. During 1998, the project laid the foundation for future expansion by approving construction of the Aurora mine. This mine, located on one of the most attractive leases in the Athabasca deposit, will exploit newly developed technologies and provide a less costly source of oil sand for decades to come. Additional expansion stages have been identified that, when completed, will increase production to 400,000 gross barrels a day by 2007. The actual pace of development has yet to be determined. Murphy's exploration and production operations in the UNITED KINGDOM are centered in the North Sea and Atlantic Margin basins. Production averaged [PHOTOGRAPH APPEARS HERE] 12

17,475 barrels of oil equivalent a day in 1998, an increase of more than 9% from a year ago. In addition to evaluating existing acreage, the Company's strategy is to build a portfolio of moderate-risk, moderate-reward prospects, with an emphasis on increasing ownership interest levels and securing operatorship where feasible. The increase in U.K. production in 1998, along with an anticipated additional 35% increase in 1999, is attributable to new low-cost fields that came on stream during 1998. Gross production from Mungo/Monan reached peak levels of 65,000 barrels of oil a day by the end of the year. Mungo is produced from a normally unmanned platform, while Monan uses a subsea system. Both fields produce to a central processing facility. Development drilling will continue over the next two years. Similarly, production from the Schiehallion field, west of the Shetland Islands, commenced during 1998. Gross production by the end of 1998 totaled approximately 86,000 barrels of oil a day. Development drilling will continue throughout 1999, building to peak gross production of 147,000 barrels of oil a day during the year. [PHOTOGRAPH APPEARS HERE] [PHOTOGRAPH APPEARS HERE] 13

[UNITED KINGDOM MAP] In 1998, Murphy acquired five additional blocks, with interests ranging from 20% to 37.5%, through U.K. licensing rounds. The Company's 1999 exploration program will concentrate on acquisition and evaluation of seismic data along with evaluation of acreage being offered in 1999 for licenses offshore the Faroe Islands and in the United Kingdom. An important milestone in Murphy's frontier program culminated with the signing of production sharing contracts covering three blocks, which Murphy will operate, offshore MALAYSIA. Blocks SK 309 (85%) and SK 311 (85%) are contiguous blocks covering 2.4 million acres in shallow waters offshore Sarawak. Previous exploration has identified a number of attractive features and both blocks contain oil and gas discoveries. Work commitments over the next five years include acquisition of seismic data and drilling of four exploratory wells, for a minimum total expenditure of $15 million. Block K (80%) covers 4.1 million undrilled acres in deep waters offshore Sabah. It adjoins two blocks held by major oil companies, one of which contains a recently announced discovery. Commitments include a seismic program plus one exploratory well over seven years, with a minimum expenditure of $14 million. [MALAYSIA MAP] 14

In 1998, Murphy was awarded a Geophysical Survey and Exploration Contract (GSEC) (80%) covering approximately 3.7 million acres in the northern Sulu Sea offshore PHILIPPINES. Under the GSEC, acquisition of seismic data is under way, with an option to drill an exploratory well. After 20 years of force majeure, Murphy gained access to part of the 3.8 million acres included in the Kharan concession (100%) in PAKISTAN during 1998. The agreement gives the Company the right to explore the southern half of Kharan and to retain rights to explore in the northern half of the concession when access can be obtained. Activity during 1999 will include acquisition of seismic data and regional studies. Murphy's holdings in ALASKA continue to position the Company in an area of renewed interest to the industry. New 3-D seismic surveys were acquired over the Challenge Island leases (25%), and a well spudded on the Red Dog prospect (12.5%) in early 1999. Development of the Northstar field (2%) was approved during 1998, but has been delayed due to presently deteriorating industry conditions. A successful farmout to an industry partner, in exchange for new 3-D seismic data and a carried interest in an optional well, reduced Murphy's interest in the Sandpiper project (28.8%). Murphy's production from Block 16 (20%) in ECUADOR totaled 7,720 barrels of oil a day in 1998, essentially flat with 1997. Additional 3-D seismic data was acquired during the year and six development wells were drilled. Plans to expand pipeline capacity could allow for significant production increases. Other frontier activity in 1998 included two unsuccessful wells in an unexplored basin north of the FALKLAND ISLANDS. Both wells indicated the presence of hydrocarbons but no commercial accumulation was found. [PHOTOGRAPH APPEARS HERE] 15

REFINING, MARKETING & TRANSPORTATION THE YEAR IN REVIEW Murphy Oil Corporation's refining, marketing and transportation strategy has been clear and effective over the past several years: lowering operating costs while increasing operational efficiency and reliability; improving the return on assets through strategic capital investments; targeting and developing prudent, cost-effective means to supply the end user; entering into joint ventures where appropriate; and continuing the Company's commitment to environmental protection and performance. The difficult environment experienced by Murphy and the entire oil industry in 1998 gave added significance to downstream operations, as the ability to convert crude oil into finished products and provide a steady, secure market became more important and made downstream assets relatively more valuable. In 1998, Murphy's downstream segment enjoyed a number of successes. One of the most promising was the ongoing endeavor with Wal-Mart. That program -- building high volume retail gasoline stations in the parking areas of Wal-Mart Supercenters under the Murphy USA(R) brand -- is successful and growing. As a result, Murphy now enjoys a leading position in the rapidly expanding market niche of gasoline sales at nontraditional outlets. In early 1999, 35 stations were in operation and plans call for a significant expansion during the year. Earnings from Murphy's downstream activities, before special items, totaled $49.2 million in 1998. Although refining margins retreated significantly during the fourth quarter of 1998 and into 1999, respectable levels were achieved for most of the year. Combined with record throughputs, the Company was able to post downstream profits second only to the record year of 1997. [PHOTOGRAPH APPEARS HERE] [MAP OF WAL-MART SITES] 16

Murphy has built an integrated presence in each of its refinery markets by providing products to 59 terminals serving approximately 550 retail and wholesale stations and numerous unbranded customers in the United States, and 10 terminals supplying almost 400 retail and wholesale stations in the United Kingdom. The Company has refineries located in Meraux, Louisiana; Superior, Wisconsin; and Milford Haven, Wales. REFINING, MARKETING & TRANSPORTATION - - ----------------------------------------------------------- (Thousands of dollars) 1998 1997 - - ----------------------------------------------------------- Income contribution* $ 49,230 56,738 Total assets 676,517 750,626 Capital expenditures 55,025 37,483 - - ----------------------------------------------------------- Crude oil processed - barrels a day 165,580 161,560 Products sold - barrels a day 174,152 163,430 Average gross margin on products sold - dollars a barrel United States $ 1.47 1.79 United Kingdom 2.81 2.90 - - ----------------------------------------------------------- *Before special items. The MERAUX REFINERY is capable of processing 100,000 barrels of crude oil a day and distributes petroleum products via pipeline and barge to an area covering 11 states. This distribution system consists of 35 terminals, 22 of which are wholly or jointly owned, and at the end of the year, supplied gasoline to 326 owned and wholesale branded stations. In 1998, the Meraux refinery set its fourth consecutive record for annual throughput, averaging 101,834 barrels of crude oil a day. The refinery posted a composite 98% onstream time during 1998. Meraux successfully completed its transition to [PHOTOGRAPH APPEARS HERE] 17

[U.S. DISTRIBUTION SYSTEM MAP] processing a medium, sour crude oil imported from Latin America in place of a more expensive light, sweet crude. Murphy realized savings in freight costs through the use of large capacity tankers able to unload at the Louisiana Offshore Oil Port (3.2%), which is connected to the refinery by pipeline. Murphy invested approximately $18 million in capital projects at Meraux in 1998 to improve efficiencies and meet U.S. Environmental Protection Agency (EPA) mandates, including completion of an upgrade to the Middle Distillate Hydrotreater that improved the refinery's ability to produce environmentally friendly products. Meraux's ongoing "green" fuels initiative is designed to produce lower sulfur gasoline and diesel fuel that will meet anticipated mandates from the EPA. This project is currently in the engineering phase, during which alternatives are being evaluated and preliminary equipment specifications and costs are being developed. Murphy's SUPERIOR REFINERY can process 35,000 barrels of crude oil a day and distributes gasoline and distillates through 21 terminals. It supplied gasoline to 226 owned and SPUR(R) branded stations in the Upper Midwest at the end of 1998. Taking advantage of the weak market for heavy sour crude, Superior processed over 9,000 barrels a day of heavy Canadian asphaltic crude, an increase of 25% over the average for recent years. As a result, 1998 was a record year for asphalt sales, as 1.8 million barrels were sold through three Company terminals in the Upper Midwest. [GRAPH - CAPITAL EXPENDITURES--REFINING, MARKETING AND TRANSPORTATION] 18

In keeping with the Company's strategy to continuously improve operating efficiencies and to comply with federal government mandates, Murphy invested over $9 million in capital projects, including a $2.3 million asphalt polymer modification project at Superior. This modification enables the refinery to produce improved asphalt grades required by the federal government to extend road life and minimize repair costs. Furthering Murphy's strategy to supply the end user, the Company opened a marine fueling terminal in Duluth, Minnesota to directly service the active Lake Superior shipping traffic. Murphy's U.K. operation includes an effective 30% interest in a refinery at MILFORD HAVEN, Wales that can process 108,000 barrels a day. Murphy transports products by rail to three distribution terminals, which in turn supply products to approximately 400 MURCO branded retail stations. At the U.K. refinery, the 1996 installation of a high-pressure hydrotreating unit has enabled the Company to expand sales of cleaner-burning diesel fuel with a sulfur content of less than 50 parts per million. The refinery was one of only three in the United Kingdom with the capability to produce this highly profitable product in 1998. Murphy produces, transports and resells crude oil in western CANADA. The Company owns interests in five crude oil pipeline systems, including the Manito (52.5%), Cactus Lake (13.1%), and North-Sask (36.1%) lines. In addition, Murphy operates a fleet of trucks that haul crude oil and natural gas liquids. [GRAPH - REFINED PRODUCTS SOLD] [U.K. DISTRIBUTION SYSTEM MAP] [PHOTOGRAPH APPEARS HERE] 19

CORPORATE RESPONSIBILITY Murphy Oil Corporation understands that its responsibilities extend beyond the bottom line. A healthy company depends on a healthy community, and a successful company creates a safe work environment. Murphy has developed and implemented operating procedures and invested in equipment upgrades that have earned excellent environmental and safety records for its operations. In addition, Murphy's investments in ongoing environmental improvements are part of a long- term commitment by the Company to address public concerns about the possible effects of carbon dioxide and other greenhouse gases on the environment. ENVIRONMENTAL IMPROVEMENTS In all of its downstream operations and surrounding communities, Murphy has achieved an outstanding record of environmental stewardship. Over the past decade, throughout the downstream segment of its business, the Company has invested more than $200 million in environmental improvement projects. In recent years, Murphy's refineries have reduced emissions of chemicals on the EPA's Toxic Release Inventory by 47%, maintained water emissions at less than 25% of permitted levels and reduced overall air emissions by more than 60%. In the United States, Murphy's marine terminal operations have achieved a 99.997% record of containment over the past 10 years. Murphy's exploration and production operations on the Outer Continental Shelf of the Gulf of Mexico have a 99% or better compliance record for meeting the aqueous discharge levels defined in its permits. In Canada, the Company's ongoing improvements in its oil and gas operations include replacing flare pits with more environmentally friendly aboveground tanks and flarestacks. EMPLOYEE SAFETY Murphy has developed operational procedures and employee training programs that have kept the number of its lost-time accidents below industry averages. These programs have won refinery safety awards at both Meraux, Louisiana and Superior, Wisconsin. In 1998, the Company's terminal operations surpassed eight consecutive years without a lost-time injury. The Company also participates in federal and local emergency response drills coordinated by the Federal Emergency Management Agency and local emergency response teams. Each year, Murphy conducts nearly 30,000 hours of employee training including first aid, marine survival, firefighting and transportation of hazardous materials. COMMUNITY PARTNERSHIPS Everywhere Murphy operates, people benefit. The Company's 1,566 employees support the educational, cultural and charitable organizations in their local communities. The Company is also active in the civic life of the areas where it operates. From scholarship programs to support for the United Way, Murphy remains committed to being a good neighbor and a responsible corporate citizen. [PHOTOGRAPH APPEARS HERE] 20

STATISTICAL SUMMARY 1998 1997 1996 1995 1994 - - ------------------------------------------------------------------------------------------------------------------------------------ EXPLORATION AND PRODUCTION Net crude oil and condensate production - barrels a day United States 7,025 9,565 10,614 12,772 12,503 Canada - light 3,219 3,351 3,774 4,417 4,775 - heavy 9,676 11,538 9,670 8,864 6,840 - offshore 4,192 224 -- -- -- - synthetic 10,500 9,341 8,163 8,832 9,065 United Kingdom 14,975 13,438 12,918 14,588 13,389 Ecuador 7,720 7,802 6,005 5,274 1,967 Other -- -- -- 117 1,038 Net natural gas liquids production - barrels a day United States 773 1,195 1,031 964 852 Canada 612 617 689 740 748 United Kingdom 436 423 346 447 151 - - ------------------------------------------------------------------------------------------------------------------------------------ Total 59,128 57,494 53,210 57,015 51,328 ==================================================================================================================================== Net natural gas sold - thousands of cubic feet a day United States 169,519 211,207 155,017 189,250 195,555 Canada 48,998 44,853 43,031 40,907 37,945 United Kingdom 12,384 12,609 15,247 10,671 10,138 Spain -- -- 7,338 10,898 12,620 - - ------------------------------------------------------------------------------------------------------------------------------------ Total 230,901 268,669 220,633 251,726 256,258 =================================================================================================================================== Total hydrocarbons produced - equivalent barrels/1/ a day 97,612 102,272 89,982 98,969 94,038 - - ------------------------------------------------------------------------------------------------------------------------------------ Estimated net hydrocarbon reserves - million equivalent barrels/1/,/2/ 379.9 362.1 337.6 333.8 327.6 - - ------------------------------------------------------------------------------------------------------------------------------------ Weighted average sales prices/3/ Crude oil and condensate - dollars a barrel United States $ 12.76 19.43 20.31 16.61 15.36 Canada/4/ - light 12.03 17.74 19.97 16.45 14.61 - heavy 6.56 10.76 14.27 12.10 10.56 - offshore 10.49 15.15 -- -- -- - synthetic 13.73 19.92 21.20 17.28 15.92 United Kingdom 12.52 18.89 21.08 16.96 15.77 Ecuador 6.76 12.17 15.96 13.03 12.07 Other -- -- -- 15.12 14.80 Natural gas liquids - dollars a barrel United States 11.50 15.82 17.00 12.62 12.19 Canada/4/ 9.16 14.87 13.69 9.70 9.21 United Kingdom 11.04 18.02 18.54 13.99 12.16 Natural gas - dollars a thousand cubic feet United States 2.18 2.57 2.60 1.64 1.91 Canada/4/ 1.34 1.35 1.10 .97 1.42 United Kingdom/4/ 2.23 2.65 2.58 2.53 2.43 Spain/4/ -- -- 2.89 2.88 2.55 - - ------------------------------------------------------------------------------------------------------------------------------------ Net wells drilled Oil wells - United States 1.8 .8 3.7 3.0 2.6 - Canada 6.0 78.9 41.6 29.6 20.7 - Other 3.1 3.3 3.6 3.7 2.7 Gas wells - United States 7.8 9.7 14.7 3.6 4.0 - Canada 4.2 19.9 33.9 2.3 14.5 - Other -- .1 -- .2 .4 Dry holes - United States .8 6.8 3.9 1.9 4.1 - Canada 7.5 8.3 6.5 5.9 6.5 - Other 1.0 1.9 1.2 .6 .5 - - ------------------------------------------------------------------------------------------------------------------------------------ Total 32.2 129.7 109.1 50.8 56.0 =================================================================================================================================== /1/ Natural gas converted on an energy equivalent basis of 6:1. /2/ At December 31. /3/ Includes intracompany transfers at market prices. /4/ U.S. dollar equivalent. 21

1998 1997 1996 1995 1994 - - ------------------------------------------------------------------------------------------------------------------------------------ REFINING Crude capacity/1/ of refineries - barrels per stream day 167,400 167,400 167,400 167,400 167,400 - - ------------------------------------------------------------------------------------------------------------------------------------ Inputs/yields at refineries - barrels a day Crude - Meraux, Louisiana 101,834 101,150 93,929 91,940 78,252 - Superior, Wisconsin 32,966 33,704 32,657 33,217 30,592 - Milford Haven, Wales 30,780 26,706 31,300 30,346 32,038 Other feedstocks 11,404 8,178 6,315 8,280 8,731 - - ------------------------------------------------------------------------------------------------------------------------------------ Total inputs 176,984 169,738 164,201 163,783 149,613 =================================================================================================================================== Gasoline 73,482 72,672 69,658 73,964 67,746 Kerosine 15,394 14,959 14,965 15,113 16,989 Diesel and home heating oils 50,506 44,681 43,514 39,351 35,553 Residuals 21,310 20,852 19,756 19,641 15,444 Asphalt, LPG and other 12,565 13,139 12,513 10,158 10,077 Fuel and loss 3,727 3,435 3,795 5,556 3,804 - - ------------------------------------------------------------------------------------------------------------------------------------ Total yields 176,984 169,738 164,201 163,783 149,613 =================================================================================================================================== Average cost of crude inputs to refineries - dollars a barrel United States $ 12.55 18.54 21.05 17.34 15.81 United Kingdom 13.62 20.12 21.66 17.59 16.32 - - ------------------------------------------------------------------------------------------------------------------------------------ MARKETING Products sold - barrels a day United States/2/ - Gasoline 60,990 62,244 58,726 61,690 56,310 - Kerosine 10,170 9,301 9,644 9,626 11,355 - Diesel and home heating oils 40,403 36,192 34,797 31,237 27,318 - Residuals 16,170 16,527 15,415 14,775 10,454 - Asphalt, LPG and other 9,887 9,945 9,008 8,815 7,754 - - ------------------------------------------------------------------------------------------------------------------------------------ 137,620 134,209 127,590 126,143 113,191 - - ------------------------------------------------------------------------------------------------------------------------------------ United Kingdom - Gasoline 14,058 11,467 13,919 14,277 16,601 - Kerosine 4,369 3,795 4,353 4,387 6,044 - Diesel and home heating oils 10,884 7,638 8,981 6,647 9,200 - Residuals 5,203 4,215 4,351 4,993 5,157 - LPG and other 1,579 1,862 2,011 930 3,264 - - ------------------------------------------------------------------------------------------------------------------------------------ 36,093 28,977 33,615 31,234 40,266 - - ------------------------------------------------------------------------------------------------------------------------------------ Canada 439 244 254 283 246 - - ------------------------------------------------------------------------------------------------------------------------------------ Total products sold/2/ 174,152 163,430 161,459 157,660 153,703 =================================================================================================================================== Average gross margin on products sold - dollars a barrel United States/2/ $ 1.47 1.79 .27 .47 1.14 United Kingdom 2.81 2.90 2.08 2.26 2.17 - - ------------------------------------------------------------------------------------------------------------------------------------ Branded retail outlets/1/ United States 552 585 527 514 588 United Kingdom 389 396 424 465 470 Canada 8 6 7 7 8 - - ------------------------------------------------------------------------------------------------------------------------------------ TRANSPORTATION Pipeline throughputs of crude oil - Canada - barrels a day 170,236 188,685 183,130 173,720 159,517 - - ------------------------------------------------------------------------------------------------------------------------------------ STOCKHOLDER AND EMPLOYEE DATA Common shares outstanding/1/ (thousands) 44,950 44,891 44,862 44,833 44,832 Number of stockholders of record/1/ 3,684 3,899 4,093 4,873 4,778 Number of full-time and part-time employees/1/ 1,566 1,446 1,406 1,889 1,827 Average number of full-time and part-time employees 1,498 1,421 1,777 1,874 1,852 Salaries, wages and benefits (thousands) $ 97,307 92,495 95,583 96,035 93,216 - - ------------------------------------------------------------------------------------------------------------------------------------ /1/ At December 31. /2/ Restated for 1997, 1996, 1995 and 1994. 22

DIRECTORS R. Madison Murphy/1/ Chairman Murphy Oil Corporation El Dorado, Arkansas Director since 1993 Claiborne P. Deming/1/ President and Chief Executive Officer Murphy Oil Corporation El Dorado, Arkansas Director since 1993 B. R. R. Butler/3/,/4/ Managing Director, Retired The British Petroleum Company p.l.c. Holbeton, Devon, England Director since 1991 George S. Dembroski/2/,/3/ Vice Chairman, Retired RBC Dominion Securities Limited Toronto, Ontario, Canada Director since 1995 H. Rodes Hart/1/,/3/,/4/ Chairman and Chief Executive Officer Franklin Industries, Inc. Nashville, Tennessee Director since 1975 Vester T. Hughes Jr./2/,/4/ Partner Hughes & Luce Dallas, Texas Director since 1973 C. H. Murphy Jr./1/,/3/ Former Chairman of the Board Murphy Oil Corporation El Dorado, Arkansas Director since 1950 Michael W. Murphy/1/,/2/,/3/ President Marmik Oil Company El Dorado, Arkansas Director since 1977 William C. Nolan Jr./1/,/2/,/3/ Partner Nolan and Alderson El Dorado, Arkansas Director since 1977 Caroline G. Theus/3/,/4/ President Inglewood Land and Development Company Alexandria, Louisiana Director since 1985 Lorne C. Webster/2/,/3/ Chairman and Chief Executive Officer Prenor Group Ltd. Montreal, Quebec, Canada Director since 1989 OFFICERS R. Madison Murphy Chairman Claiborne P. Deming President and Chief Executive Officer Steven A. Cosse' Senior Vice President and General Counsel Herbert A. Fox Jr. Vice President Bill H. Stobaugh Vice President Odie F. Vaughan Treasurer Ronald W. Herman Controller Walter K. Compton Secretary DIRECTORS EMERITI William C. Nolan George S. Ishiyama Committees of the Board /1/ Member of the Executive Committee chaired by Mr. R. Madison Murphy. /2/ Member of the Audit Committee chaired by Mr. Hughes. /3/ Member of the Executive Compensation and Nominating Committee chaired by Mr. William C. Nolan Jr. /4/ Member of the Public Policy and Environmental Committee chaired by Mr. Butler. 23

PRINCIPAL SUBSIDIARIES MURPHY EXPLORATION & PRODUCTION COMPANY 131 South Robertson Street New Orleans, Louisiana 70112 (504) 561-2811 Mailing Address: P. O. Box 61780 New Orleans, Louisiana 70161-1780 Engaged worldwide in crude oil and natural gas exploration and production. Enoch L. Dawkins President John C. Higgins Senior Vice President, U.S. Exploration and Production S. J. Carboni Jr. Vice President, U.S. Production James R. Murphy Vice President, U.S. Exploration David M. Wood Vice President, Frontier Exploration and Production Steven A. Cosse' Vice President and General Counsel Odie F. Vaughan Vice President and Treasurer Bobby R. Campbell Controller Walter K. Compton Secretary MURPHY OIL USA, INC. 200 Peach Street El Dorado, Arkansas 71730 (870) 862-6411 Mailing Address: P. O. Box 7000 El Dorado, Arkansas 71731-7000 Engaged in refining, marketing and transporting of petroleum products in the United States. Herbert A. Fox Jr. President Charles A. Ganus Vice President, Marketing Frederec C. Green Vice President, Manufacturing and Crude Oil Supply Steven A. Cosse' Vice President and General Counsel Odie F. Vaughan Treasurer Ronald W. Herman Controller Walter K. Compton Secretary MURPHY OIL COMPANY LTD. 2100-555-4th Avenue S.W. Calgary, Alberta T2P 3E7 (403) 294-8000 Mailing Address: P. O. Box 2721, Station M Calgary, Alberta T2P 3Y3 Canada Engaged in crude oil and natural gas exploration and production; extraction and sale of synthetic crude oil; purchasing, transporting and reselling of crude oil; and marketing of petroleum products in Canada. Harvey Doerr President W. Patrick Olson Vice President, Production R. D. Urquhart Vice President, Supply and Transportation Robert L. Lindsey Vice President, Finance and Secretary Odie F. Vaughan Treasurer MURPHY EASTERN OIL COMPANY Winston House, Dollis Park, Finchley London N3 1HZ, England 181-371-3333 Provides technical and professional services to certain of Murphy Oil Corporation's subsidiaries engaged in crude oil and natural gas exploration and production in the Eastern Hemisphere and refining, marketing and transporting of petroleum products in the United Kingdom. W. Michael Hulse President James N. Copeland Vice President, Legal and Personnel Ijaz Iqbal Vice President Odie F. Vaughan Treasurer Walter K. Compton Secretary 24

CORPORATE INFORMATION CORPORATE OFFICES 200 Peach Street El Dorado, Arkansas 71730 (870) 862-6411 MAILING ADDRESS P. O. Box 7000 El Dorado, Arkansas 71731-7000 INTERNET ADDRESS http://www.murphyoilcorp.com E-MAIL ADDRESS murphyoil@murphyoilcorp.com STOCK EXCHANGE LISTINGS Trading Symbol: MUR New York Stock Exchange The Toronto Stock Exchange TRANSFER AGENTS Harris Trust Company of New York 77 Water Street New York, New York 10005 Mailing address: c/o Harris Trust and Savings Bank P. O. Box 830 Chicago, Illinois 60690-9972 Montreal Trust Company of Canada 151 Front Street West Toronto, Ontario M5J 2N1 REGISTRAR Harris Trust Company of New York 77 Water Street New York, New York 10005 ANNUAL MEETING The annual meeting of the Company's shareholders will be held at 10 a.m. on May 12, 1999, at the South Arkansas Arts Center, 110 East 5th Street, El Dorado, Arkansas. A formal notice of the meeting, together with a proxy statement and proxy form, will be mailed to all shareholders. INQUIRIES Inquiries regarding shareholder account matters should be addressed to: Walter K. Compton Secretary Murphy Oil Corporation P. O. Box 7000 El Dorado, Arkansas 71731-7000 Members of the financial community should direct their inquiries to: Kevin G. Fitzgerald Director of Investor Relations Murphy Oil Corporation P. O. Box 7000 El Dorado, Arkansas 71731-7000 (870) 864-6272 ELECTRONIC PAYMENT OF DIVIDENDS Shareholders may have dividends deposited directly into their bank accounts by electronic funds transfer. Authorization forms may be obtained from: Harris Trust and Savings Bank P. O. Box 830 Chicago, Illinois 60690-9972 (312) 461-2457 inside back cover

EXHIBIT 13 APPENDIX MURPHY OIL CORPORATION - CIK 0000717423 Appendix to Electronically Filed Exhibit 13 (1998 Annual Report to Security Holders, Which is Incorporated in This Form 10-K) Providing a Narrative of Graphic and Image Material Appearing on Pages 1 Through 20 of Paper Format Exhibit 13 Page No. Map Narrative - - ---------- ------------- 8 Gulf of Mexico - The locations and areal extent of acreage leased by the Company in the Gulf of Mexico (offshore Texas, Louisiana, Mississippi, Alabama and Florida) are shown. Each lease is colored to denote either (1) production or (2) exploration. 12 Western Canada - The locations of the Company's productive oil and gas fields in the Canadian provinces of British Columbia, Alberta, Saskatchewan and Manitoba are shown. Each field is colored to denote (1) natural gas, (2) light oil, (3) heavy oil, or (4) oil sands. 14 United Kingdom - The locations and areal extent of acreage under license by the Company are shown in the U.K. sector of the North Sea and the Atlantic Margin area west of Britain and Ireland. Each lease is colored to denote either (1) production or (2) exploration. 14 Malaysia - The locations and areal extent of the Company's recently acquired Malaysian acreage offshore Sarawak and Sabah are shown. 16 Wal-Mart Sites Operational as of February 1999 - The locations of the Company's 35 gasoline stations in the parking areas of Wal-Mart stores in the southeastern United States are shown. 18 United States - The locations of the Company's refineries in Superior, Wisconsin and Meraux, Louisiana are shown along with depictions of the routes and means of moving finished products from the refineries into marketing areas and depictions of the locations of terminal facilities used to store and/or distribute products to retail outlets, wholesalers and consumers in the Upper Midwest and the Southeast. 19 United Kingdom - The Company's jointly owned refinery in Milford Haven, Wales is shown along with depictions of the routes and means of moving finished products from the refinery into U.K. marketing areas and depictions of the locations of terminal facilities used to store and/or distribute products to retail outlets, wholesalers and consumers. Ex. 13A-1

MURPHY OIL CORPORATION - CIK 0000717423 Appendix to Electronically Filed Exhibit 13 (Contd.) Exhibit 13 Page No. Picture Narrative - - ---------- ----------------- 4 Claiborne P. Deming, President and Chief Executive Officer of Murphy Oil Corporation, is pictured. 7 A nighttime view of the production platform for the Hibernia oil field offshore eastern Canada is shown. 9 A semisubmersible drilling rig is shown at Ewing Bank Block 994 in the deepwater Gulf of Mexico. This successful well resulted in an important discovery for the Company in 1998. 10 An onshore drilling rig is shown completing the successful Guidry No. 1 well in Vermilion Parish, Louisiana. This well will likely prove up 50 billion cubic feet of reserves. 12 A view is shown of the processing and upgrading facility at Syncrude Canada Ltd. near Fort McMurray, Alberta. Based on current expansion plans, total synthetic oil production at Syncrude will increase to 400,000 barrels a day by 2007. 13 The floating production storage and offloading vessel on location at the Schiehallion field west of the Shetland Islands is shown. 13 The Mungo field's unmanned production platform, flanked by a jack-up rig used to continue development drilling, is shown on location in the U.K. North Sea. 15 An oil processing facility in Block 16 Ecuador is shown. Murphy's production in Ecuador could increase significantly upon completion of a planned crude oil pipeline expansion. 16 A Murphy USA station located in the parking area of the Wal-Mart Supercenter in Callaway, Florida is shown. The Company will significantly expand the number of its stations at Wal-Mart stores during 1999. 17 Processing units are shown at the Company's Meraux, Louisiana refinery, which posted its fourth consecutive record for annual crude oil throughput in 1998. 19 Storage tanks and a ship fueling at the Company's new marine terminal at Duluth, Minnesota are shown. The terminal was opened in 1998 to service shipping traffic on Lake Superior. Ex. 13A-2

MURPHY OIL CORPORATION - CIK 0000717423 Appendix to Electronically Filed Exhibit 13 (Contd.) Exhibit 13 Page No. Picture Narrative (Contd.) - - ---------- -------------------------- 20 Claiborne Deming, President and CEO, is shown presenting Judy Quick, an employee at the Company's Meraux refinery, with the 1998 Community Spirit Award in recognition of her outstanding volunteer activities as an employee at the refinery. Graph Narrative --------------- 1 INCOME CONTRIBUTION FROM CONTINUING OPERATIONS BY FUNCTION Excludes special items and Corporate activities. Scale 0 to 160 (millions of dollars) 1994 1995 1996 1997 1998 ---- ----- ----- ----- ---- Refining, Marketing and Transportation (top) 30 2 14 57 49 Exploration and Production (bottom) 45 30 102 85 6 ---- ----- ----- ----- ---- Totals 75 32 116 142 55 ==== ===== ===== ===== ==== This stacked vertical bar graph has totals printed above bars. 1 ESTIMATED NET PROVED HYDROCARBON RESERVES Scale 0 to 450 (millions of oil equivalent barrels) 1994 1995 1996 1997 1998 ---- ----- ----- ----- ---- Ecuador and Other (top) 36 30 27 31 32 United Kingdom 30 48 58 63 63 Canada 166 159 157 176 188 United States (bottom) 96 97 96 92 97 ---- ----- ----- ----- ---- Totals 328 334 338 362 380 ==== ===== ===== ===== ==== This stacked vertical bar graph has totals printed above bars. 2 CASH FLOW FROM CONTINUING OPERATIONS BY FUNCTION Excludes special items, Corporate activities, and changes in noncash working capital. Scale 0 to 500 (millions of dollars) 1994 1995 1996 1997 1998 ---- ----- ----- ----- ---- Refining, Marketing and Transportation (top) 38 51 59 100 89 Exploration and Production (bottom) 316 270 343 365 268 ---- ----- ----- ----- ---- Totals 354 321 402 465 357 ===== ===== ===== ===== ==== This stacked vertical bar graph has totals printed above bars. Ex. 13A-3

MURPHY OIL CORPORATION - CIK 0000717423 Appendix to Electronically Filed Exhibit 13 (Contd.) Exhibit 13 Page No. Graph Narrative (Continued) -------- --------------- 2 CAPITAL EXPENDITURES BY FUNCTION Scale 0 to 500 (millions of dollars) 1994 1995 1996 1997 1998 ---- ---- ---- ---- ---- Corporate (top) 5 2 1 7 2 Refining, Marketing and Transportation 95 53 43 38 55 Exploration and Production (bottom) 286 232 374 423 332 ---- ---- ---- ---- ---- Totals 386 287 418 468 389 ==== ==== ==== ==== ==== This stacked vertical bar graph has totals printed above bars. 4 HYDROCARBON PRODUCTION REPLACEMENT Scale 0 to 180 (percent of production) 1994 1995 1996 1997 1998 ---- ---- ---- ---- ---- 147 117 111 165 150 This vertical bar graph has values printed above bars. 6 NET HYDROCARBONS PRODUCED Scale 0 to 120 (thousands of oil equivalent barrels a day) 1994 1995 1996 1997 1998 ---- ---- ---- ---- ---- Ecuador and Other (top) 5 7 7 8 8 United Kingdom 15 17 16 16 18 Canada 28 30 30 32 36 United States (bottom) 46 45 37 46 36 ---- ---- ---- ---- ---- Totals 94 99 90 102 98 ==== ==== ==== ==== ==== This stacked vertical bar graph has totals printed above bars. 10 CAPITAL EXPENDITURES - EXPLORATION AND PRODUCTION Scale 0 to 480 (millions of dollars) 1994 1995 1996 1997 1998 ---- ---- ---- ---- ---- Ecuador and Other (top) 62 29 21 38 32 United Kingdom 34 33 69 91 71 Canada 111 99 99 147 108 United States (bottom) 79 71 185 147 121 ---- ---- ---- ---- ---- Totals 286 232 374 423 332 ==== ==== ==== ==== ==== This stacked vertical bar graph has values printed above bars. 11 WORLDWIDE EXTRACTION COSTS Scale 0 to 10.50 (dollars per equivalent barrel) 1994 1995 1996 1997 1998 ---- ---- ---- ---- ---- Depreciation, Depletion and Amortization (top) 4.71 5.06 4.48 4.62 4.58 Production Expense (bottom) 4.72 4.64 4.87 4.41 4.35 ---- ---- ---- ---- ---- Totals 9.43 9.70 9.35 9.03 8.93 ==== ==== ==== ==== ==== This stacked vertical bar graph has values for each component printed within bars and totals printed above bars. Ex. 13A-4

MURPHY OIL CORPORATION - CIK 0000717423 Appendix to Electronically Filed Exhibit 13 (Contd.) Exhibit 13 Page No. Graph Narrative (Continued) - - --------- --------------- 18 CAPITAL EXPENDITURES - REFINING, MARKETING AND TRANSPORTATION Scale 0 to 120 (millions of dollars) 1994 1995 1996 1997 1998 ---- ---- ---- ---- ---- Canada (top) 3 4 8 5 3 United Kingdom 12 22 14 4 7 United States (bottom) 80 28 21 29 45 ---- ---- ---- ---- ---- Totals 95 54 43 38 55 ==== ==== ==== ==== ==== This stacked vertical bar graph has totals printed above bars. 19 REFINED PRODUCTS SOLD Scale 0 to 200 (thousands of barrels a day) 1994 1995 1996 1997 1998 ---- ---- ---- ---- ---- United Kingdom (top) 40 31 33 29 36 United States (bottom) 114 127 128 134 138 ---- ---- ---- ---- ---- Totals 154 158 161 163 174 ==== ==== ==== ==== ==== This stacked vertical bar graph has totals printed above bars. Ex. 13A-5

EXHIBIT 21 MURPHY OIL CORPORATION SUBSIDIARIES OF THE REGISTRANT AS OF DECEMBER 31, 1998 Percentage of Voting Securities State or Other Owned by Jurisdiction Immediate Name of Company of Incorporation Parent - - --------------------------------------------------- ---------------- --------- MURPHY OIL CORPORATION (REGISTRANT) A. El Dorado Engineering Inc. Delaware 100.0 1. El Dorado Contractors Inc. Delaware 100.0 B. Murphy Eastern Oil Company Delaware 100.0 C. Murphy Exploration & Production Company (formerly Ocean Drilling & Exploration Company) Delaware 100.0 1. Canam Offshore A. G. (Switzerland) Switzerland 100.0 2. Canam Offshore Limited Bahamas 100.0 a. Murphy Ireland Offshore Limited Bahamas 100.0 b. Ocean Drilling Limited Bahamas 100.0 3. El Dorado Exploration, S.A. Delaware 100.0 4. Mentor Holding Corporation Delaware 100.0 a. Mentor Excess and Surplus Lines Insurance Company Delaware 100.0 b. Mentor Insurance and Reinsurance Company Louisiana 100.0 c. Mentor Insurance Limited Bermuda 99.993 (1) Mentor Insurance Company (U.K.) Limited England 100.0 (2) Mentor Underwriting Agents (U.K.) Limited England 100.0 5. MEPCO Venezuela, Ltd. Bahamas 100.0 6. Murphy Bangladesh Oil Company Delaware 100.0 7. Murphy Brazil Exploracao e Producao de Petroleo e Gas Ltda. (see company C21a below) Brazil 90.0 8. Murphy Building Corporation Delaware 100.0 9. Murphy Central Asia Oil Co., Ltd. Bahamas 100.0 10. Murphy Denmark Oil Company Delaware 100.0 11. Murphy Ecuador Oil Company Ltd. Bermuda 100.0 12. Murphy Equatorial Guinea Oil Company Delaware 100.0 13. Murphy Exploration (Alaska), Inc. Delaware 100.0 14. Murphy Falklands Oil Co., Ltd. Bahamas 100.0 15. Murphy Faroes Oil Co., Ltd. Bahamas 100.0 16. Murphy France Oil Company Delaware 100.0 17. Murphy Indus Energy Ltd. Bahamas 100.0 18. Murphy Ireland Oil Company Delaware 100.0 19. Murphy Italy Oil Company Delaware 100.0 20. Murphy New Zealand Oil Company Delaware 100.0 21. Murphy Overseas Ventures Inc. Delaware 100.0 a. Murphy Brazil Exploracao e Producao de Petroleo e Gas Ltda. (see company C7 above) Brazil 10.0 22. Murphy Pacific Rim, Ltd. Bahamas 100.0 23. Murphy Pakistan Oil Company Delaware 100.0 24. Murphy Philippines Oil Co., Ltd. Bahamas 100.0 25. Murphy Sabah Oil Co., Ltd. Bahamas 100.0 26. Murphy Sarawak Oil Co., Ltd. Bahamas 100.0 27. Murphy Somali Oil Company Delaware 100.0 28. Murphy South Asia Oil Co., Ltd. Bahamas 100.0 29. Murphy South Atlantic Oil Company Delaware 100.0 Ex. 21-1

EXHIBIT 21 (Contd.) MURPHY OIL CORPORATION SUBSIDIARIES OF THE REGISTRANT AS OF DECEMBER 31, 1998 (Contd.) Percentage of Voting Securities State or Other Owned by Jurisdiction Immediate Name of Company of Incorporation Parent - - ------------------------------------------------------ ---------------- --------- MURPHY OIL CORPORATION (REGISTRANT) - Contd. C. Murphy Exploration & Production Company - Contd. 30. Murphy-Spain Oil Company Delaware 100.0 31. Murphy Venezuela Oil Company, S.A. Panama 100.0 32. Murphy Western Oil Company Delaware 100.0 33. Murphy Yemen Oil Company Delaware 100.0 34. Norske Murphy Oil Company Delaware 100.0 35. Norske Ocean Exploration Company Delaware 100.0 36. Ocean Exploration Company Delaware 100.0 37. Ocean France Oil Company Delaware 100.0 38. Ocean Gabon Oil Company Delaware 100.0 39. Ocean International Finance Corporation Delaware 100.0 40. Odeco Drilling (UK) Limited England 100.0 41. Odeco Gabon Oil Company Delaware 100.0 42. Odeco International Corporation Panama 100.0 43. Odeco Italy Oil Company Delaware 100.0 44. Sub Sea Offshore (M) Sdn. Bhd. Malaysia 60.0 D. Murphy Oil Company, Ltd. Canada 100.0 1. 340236 Alberta Ltd. Canada 100.0 2. Murphy Atlantic Offshore Finance Company Ltd. Canada 100.0 3. Murphy Atlantic Offshore Oil Company Ltd. Canada 100.0 4. Spur Refined Products Ltd. Canada 100.0 5. Wascana Pipe Line Ltd. Canada 100.0 E. Murphy Oil USA, Inc. Delaware 100.0 1. Arkansas Oil Company Delaware 100.0 2. Murphy Gas Gathering Inc. Delaware 100.0 3. Murphy Latin America Refining & Marketing, Inc. Delaware 100.0 4. Murphy LOOP, Inc. Delaware 100.0 5. Murphy Oil Trading Company (Eastern) Delaware 100.0 6. Spur Oil Corporation Delaware 100.0 7. Superior Crude Oil Trading Company Delaware 100.0 F. Murphy Realty Inc. Delaware 100.0 G. Murphy Ventures Corporation Delaware 100.0 H. New Murphy Oil (UK) Corporation Delaware 100.0 1. Murphy Petroleum Limited England 100.0 a. Alnery No. 166 Ltd. England 100.0 b. H. Hartley (Doncaster) Ltd. England 100.0 c. Murco Petroleum Limited England 100.0 (1) European Petroleum Distributors Ltd. England 100.0 (2) Murco Petroleum (Ireland) Ltd. Ireland 100.0 I. Rowel Corporation Delaware 100.0 Ex. 21-2

EXHIBIT 23 INDEPENDENT AUDITORS' CONSENT ----------------------------- The Board of Directors Murphy Oil Corporation: We consent to incorporation by reference in the Registration Statements (Nos. 2-82818, 2-86749, 2-86760, and 333-27407) on Form S-8 and (No. 33-55161) on Form S-3 of Murphy Oil Corporation of our report dated March 1, 1999, relating to the consolidated balance sheets of Murphy Oil Corporation and Consolidated Subsidiaries as of December 31, 1998 and 1997, 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, 1998, which report is included in the December 31, 1998, annual report on Form 10-K of Murphy Oil Corporation. KPMG LLP Shreveport, Louisiana March 24, 1999 Ex. 23-1

5 THIS FINANCIAL DATA SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE AUDITED CONSOLIDATED BALANCE SHEET AT DECEMBER 31, 1998, AND THE AUDITED CONSOLIDATED STATEMENT OF INCOME FOR THE YEAR ENDED DECEMBER 31, 1998, OF MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 YEAR DEC-31-1998 DEC-31-1998 28,271 0 244,954 11,048 129,777 437,366 4,648,216 2,985,854 2,164,419 380,750 333,473 0 0 48,775 929,458 2,164,419 1,624,980 1,698,848 1,482,314 1,482,314 145,709

0 10,484 (8,277) 6,117 (14,394) 0 0 0 (14,394) (.32) (.32) INCLUDES 80,127 FOR IMPAIRMENT OF LONG-LIVED ASSETS.

EXHIBIT 99.1 UNDERTAKINGS To be incorporated by reference into Form S-8 Registration Statements Nos. 2-82818, 2-86749, 2-86760, and 333-27407, and Form S-3 Registration Statement No. 33-55161. The undersigned registrant hereby undertakes: (1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement: (i) To include any prospectus required by section 10(a)(3) of the Securities Act of 1933; (ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post- effective amendment thereof) which, individually or in the aggregate, represents a fundamental change in the information set forth in the registration statement; (iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement; (2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. (3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering. The undersigned registrant hereby undertakes that, for purposes of determining any liability under the Securities Act of 1933, each filing of the registrant's annual report pursuant to section 13(a) or section 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan's annual report pursuant to section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. The undersigned registrant hereby undertakes: (1) To deliver or cause to be delivered with the prospectus to each employee to whom the prospectus is sent or given a copy of the registrant's annual report to stockholders for its last fiscal year, unless such employee otherwise has received a copy of such report, in which case the registrant shall state in the prospectus that it will promptly furnish, without charge, a copy of such report on written request of the employee. If the last fiscal year of the registrant has ended within 120 days prior to the use of the prospectus, the annual report of the registrant for the preceding Ex. 99.1-1

fiscal year may be so delivered, but within such 120 day period the annual report for the last fiscal year will be furnished to each such employee. (2) To transmit or cause to be transmitted to all employees participating in the plan who do not otherwise receive such material as stockholders of the registrant, at the time and in the manner such material is sent to its stockholders, copies of all reports, proxy statements and other communications distributed to its stockholders generally. Where interests in a plan are registered herewith, the undersigned registrant and plan hereby undertake to transmit or cause to be transmitted promptly, without charge, to any participant in the plan who makes a written request, a copy of the then latest annual report of the plan filed pursuant to section 15(d) of the Securities Exchange Act of 1934 (Form 11-K). If such report is filed separately on Form 11-K, such form shall be delivered upon written request. If such report is filed as a part of the registrant's annual report on Form 10-K, that entire report (excluding exhibits) shall be delivered upon written request. If such report is filed as a part of the registrant's annual report to stockholders delivered pursuant to paragraph (1) or (2) of this undertaking, additional delivery shall not be required. Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue. Ex. 99.1-2