================================================================================ 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, 2000 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) <TABLE> <S> <C> Delaware 71-0361522 (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification Number) </TABLE> 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 Toronto Stock Exchange Series A Participating Cumulative New York Stock Exchange Preferred Stock Purchase Rights 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 31, 2001, as quoted by the New York Stock Exchange, was approximately $1,949,012,000. Number of shares of Common Stock, $1.00 Par Value, outstanding at January 31, 2001 was 45,047,369. Documents incorporated by reference: Portions of the Registrant's definitive Proxy Statement relating to the Annual Meeting of Stockholders on May 9, 2001 have been incorporated by reference in Part III herein. ================================================================================
MURPHY OIL CORPORATION TABLE OF CONTENTS - 2000 FORM 10-K REPORT <TABLE> <CAPTION> Page Number ------ PART I <S> <C> Item 1. Business 1 Item 2. Properties 1 Item 3. Legal Proceedings 6 Item 4. Submission of Matters to a Vote of Security Holders 7 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 17 Item 8. Financial Statements and Supplementary Data 18 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 18 PART III Item 10. Directors and Executive Officers of the Registrant 18 Item 11. Executive Compensation 18 Item 12. Security Ownership of Certain Beneficial Owners and Management 18 Item 13. Certain Relationships and Related Transactions 19 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 19 Exhibit Index 19 Signatures 21 </TABLE> 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. 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. In November 2000, Murphy acquired Beau Canada Exploration Ltd. (Beau Canada), an independent oil and gas company with exploration and production assets in western Canada. The information appearing in the 2000 Annual Report to Security Holders (2000 Annual Report) is incorporated in this Form 10-K report as Exhibit 13 and is deemed to be filed as part of this Form 10-K report as indicated under Items 1, 2 and 7. A narrative of the graphic and image information that appears in the paper format version of Exhibit 13 is included in the electronic Form 10-K document as an appendix to Exhibit 13. In addition to the following information about each business activity, data about Murphy's operations, properties and business segments, including revenues by class of products and financial information by geographic area, are provided on pages 7 through 15, F-9, F-21 through F-23, and F-26 through F-28 of this Form 10-K report and on pages 4 through 8 of the 2000 Annual Report. Exploration and Production During 2000, 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 2000 was in the United States, Canada, the United Kingdom and Ecuador; its natural gas was produced and sold in the United States, Canada and the United Kingdom. MOCL owns a 5% interest in Syncrude Canada Ltd., which utilizes its assets to extract bitumen from oil sand deposits in northern Alberta and to upgrade this into synthetic crude oil. Subsidiaries of Murphy Expro conducted exploration activities in various other areas including Malaysia, the Faroe Islands, Ireland and Spain. Murphy's estimated net quantities of proved oil and gas reserves and proved developed oil and gas reserves at December 31, 1997, 1998, 1999 and 2000 by geographic area are reported on page F-25 of this Form 10-K report. Murphy has not filed and is not required to file any estimates of its total net proved oil or gas reserves on a recurring basis with any federal or foreign governmental regulatory authority or agency other than the U.S. Securities and Exchange Commission. Annually, Murphy reports gross reserves of properties operated in the United States to the U.S. Department of Energy; such reserves are derived from the same data from which estimated net proved reserves of such properties are determined. Net crude oil, condensate, and gas liquids production and sales, and net natural gas sales by geographic area with weighted average sales prices for each of the five years ended December 31, 2000 are shown on page 9 of the 2000 Annual Report. 1
Production expenses for the last three years in U.S. dollars per equivalent barrel are discussed on page 11 of this Form 10-K report. For purposes of these computations, natural gas sales volumes are converted to equivalent barrels of crude oil using a ratio of six thousand cubic feet (MCF) of natural gas to one barrel of crude oil. Supplemental disclosures relating to oil and gas producing activities are reported on pages F-24 through F-29 of this Form 10-K report. At December 31, 2000, 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. <TABLE> <CAPTION> Nonproducing Producing Total ------------------ ------------------ ----------------- Area (Thousands of acres) Gross Net Gross Net Gross Net - ------------------------- ------ ------- ------ ----- ------ ------ <S> <C> <C> <C> <C> <C> <C> United States - Onshore 4 3 40 20 44 23 - Gulf of Mexico 878 522 302 112 1,180 634 - Frontier 119 44 - - 119 44 ------ ------- ------ ----- ------ ------ Total United States 1,001 569 342 132 1,343 701 ------ ------- ------ ----- ------ ------ Canada - Onshore 1,318 894 1,178 368 2,496 1,262 - Offshore 12,519 2,118 56 3 12,575 2,121 - Oil sands 160 8 96 5 256 13 ------ ------- ------ ----- ------ ------ Total Canada 13,997 3,020 1,330 376 15,327 3,396 ------ ------- ------ ----- ------ ------ United Kingdom 1,297 418 79 11 1,376 429 Ecuador - - 494 99 494 99 Malaysia 6,498 5,319 - - 6,498 5,319 Ireland 954 239 - - 954 239 Spain 330 99 - - 330 99 ------ ------- ------ ---- ------ ------ Totals 24,077 9,664 2,245 618 26,322 10,282 ====== ======= ====== ==== ====== ====== </TABLE> As used in the three tables that follow, "gross" wells are the total wells in which all or part of the working interest is owned by Murphy, and "net" wells are the total of the Company's fractional working interests in gross wells expressed as the equivalent number of wholly owned wells. The following table shows the number of oil and gas wells producing or capable of producing at December 31, 2000. <TABLE> <CAPTION> Oil Wells Gas Wells ------------------ ------------------ Country Gross Net Gross Net - ------- ------- ------- ------ ----- <S> <C> <C> <C> <C> United States 287 123.8 190 73.8 Canada 3,068 798.0 850 385.0 United Kingdom 109 13.1 21 1.6 Ecuador 64 12.8 - - -------- ------- ------ ------ Totals 3,528 947.7 1,061 460.4 ======== ======= ====== ====== Wells included above with multiple completions and counted as one well each 82 38.2 76 59.0 </TABLE> 2
Murphy's net wells drilled in the last three years are shown in the following table. <TABLE> <CAPTION> 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 -------- ---- ------- ---- ------- --- ------- --- ------- --- ------- --- <S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> 2000 - ---- Exploratory 2.0 3.9 6.4 12.0 .1 .3 - - .8 - 9.3 16.2 Development .3 - 51.7 4.0 .6 .1 1.0 - - - 53.6 4.1 1999 - ---- Exploratory 1.4 1.0 5.3 5.5 - - .4 - - - 7.1 6.5 Development .6 - 13.7 .2 1.0 - .8 - - - 16.1 .2 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 - </TABLE> Murphy's drilling wells in progress at December 31, 2000 are shown below. <TABLE> <CAPTION> Exploratory Development Total --------------- ------------- ----------------- Country Gross Net Gross Net Gross Net - ------- ----- --- ----- --- ----- --- <S> <C> <C> <C> <C> <C> <C> United States 3 .7 - - 3 .7 Canada 11 6.5 5 1.8 16 8.3 United Kingdom - - 4 .3 4 .3 ----- --- ---- ---- ---- ---- Totals 14 7.2 9 2.1 23 9.3 ===== === ==== ==== ==== ==== </TABLE> Additional information about current exploration and production activities is reported on pages 1 through 6 of the 2000 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, 2000 are shown in the following table. 3
<TABLE> <CAPTION> Milford Haven, Meraux, Superior, Wales Louisiana Wisconsin (Murco's 30%) Total --------- --------- ----------- ----- <S> <C> <C> <C> <C> 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 3,400 5,400 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. </TABLE> MOUSA markets refined products through a network of retail gasoline stations and branded and unbranded wholesale customers in a 23-state area of the southern and midwestern United States. Murphy's retail stations are primarily located in the parking areas of Wal-Mart stores and use the brand name Murphy USA(R). Branded wholesale customers use the brand name SPUR(R). Refined products are supplied from 11 terminals that are wholly owned and operated by MOUSA, 16 terminals that are jointly owned and operated by others, and numerous terminals owned by others. Of the terminals wholly owned or jointly owned, four are supplied by marine transportation, three are supplied by truck, two are adjacent to MOUSA's refineries and 18 are supplied by pipeline. MOUSA receives products at the terminals owned by others either in exchange for deliveries from the Company's terminals or by outright purchase. At December 31, 2000, the Company marketed products through 276 Murphy USA stations and 436 SPUR stations (19 of which are either owned or leased by the Company). MOUSA plans to add up to 125 new Murphy USA stations at Wal-Mart sites in the southern and midwestern United States in 2001. At the end of 2000, Murco distributed refined products in the United Kingdom from the Milford Haven refinery, three wholly owned terminals supplied by rail, six terminals owned by others where products are received in exchange for deliveries from the Company's terminals, and 386 branded stations under the brand names MURCO and EP. Murphy owns a 20% interest in a 120-mile refined products pipeline, with a capacity of 165,000 barrels a day, that transports products from the Meraux refinery to two common carrier pipelines serving the southeastern United States. The Company also owns a 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 LLC, which provides deepwater unloading accommodations off the Louisiana coast for oil tankers and onshore facilities for storage of crude oil. A crude oil pipeline with a diameter of 24 inches connects LOOP storage at Clovelly, Louisiana to the Meraux refinery. Murphy owns 29.4% of the first 22 miles of this pipeline from Clovelly to Alliance, Louisiana and 100% of the remaining 24 miles from Alliance to Meraux. The pipeline is connected to another company's pipeline system, allowing crude oil transported by that system to also be shipped to the Meraux refinery. 4
At December 31, 2000, 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. In 2001, the Company entered into an agreement to sell its Canadian pipeline and trucking operation. <TABLE> <CAPTION> Pipeline Description Percent Miles Bbls./Day Route - -------- ----------- ------- ----- --------- ----- <S> <C> <C> <C> <C> <C> Manito Dual heavy oil 100 101 70,000 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 76.3 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 100 108 45,000 Regina, Sask. to U.S. border Senlac Dual heavy oil 100 28 15,000 Senlac to Unity, Sask. </TABLE> 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, 2000 are reported on pages 1, 3, 7, 8 and 10 of the 2000 Annual Report. Employees At December 31, 2000, Murphy had 3,109 employees - 1,711 full-time and 1,398 part-time. 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 purchases refined products and may be required to respond to operating and pricing policies of others, including producing country governments from whom it makes purchases. Additional information concerning current conditions of the Company's business is reported under the caption "Outlook" on page 17 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" beginning on page 15 of this Form 10-K report), preferential and discriminatory awarding of oil and gas leases, restrictions on drilling and/or production, restraints and controls on imports and exports, safety, and relationships between employers and employees. Because these and other factors too numerous to list are subject to constant changes caused by governmental and political considerations and are often made in great haste in response to changing internal and worldwide economic conditions and to actions of other governments or specific events, it is not practical to attempt to predict the effects of such factors on Murphy's future operations and earnings. Murphy's business is subject to operational hazards and risks normally associated with the exploration for and production of oil and natural gas and the refining, marketing and transportation of crude oil and petroleum products. The occurrence of a significant event could result in the loss of hydrocarbons, environmental pollution, personal injury and loss of life, damage to the property of the Company and others, and loss of revenues, and could subject the Company to substantial fines and/or claims for punitive damages. Murphy maintains insurance against certain, but not all, hazards that could arise from its operations, and such insurance is believed to be reasonable for the hazards and risks faced by the Company. There can be no assurance that such insurance will be adequate to offset lost revenues or costs associated with potentially significant events or that insurance coverage will continue to be available in the future on terms that justify its purchase. The occurrence of a significant event that is not fully insured could have a material adverse effect on the Company's financial condition and results of operations in the future. 5
Executive Officers of the Registrant The age at January 1, 2001, 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 43; Chairman of the Board since October 1994 and Director and Member of the Executive Committee since 1993. Mr. Murphy served as Executive Vice President and Chief Financial and Administrative Officer from 1993 to 1994; 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 46; President and Chief Executive Officer since October 1994 and Director and Member of the Executive Committee since 1993. He served as Executive Vice President and Chief Operating Officer from 1992 to 1993 and President of MOUSA from 1989 to 1992. Steven A. Cosse' - Age 53; 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 Ocean Drilling & Exploration Company (ODECO), a majority-owned subsidiary of Murphy. Herbert A. Fox Jr. - Age 66; 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 49; Vice President since May 1995, when he joined the Company. Prior to that, he had held various engineering, planning and managerial positions, the most recent being with an engineering consulting firm. Odie F. Vaughan - Age 64; Treasurer since August 1991. From 1975 through July 1991, he was with ODECO as Vice President of Taxes and Treasurer. John W. Eckart - Age 42; Controller since March 2000. Mr. Eckart had been Assistant Controller since February 1995. He joined the Company as Auditing Manager in 1990. Walter K. Compton - Age 38; 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 On June 29, 2000, the U.S. Government and the State of Wisconsin each filed a lawsuit against Murphy in the U.S. District Court for the Western District of Wisconsin. The State action was subsequently dismissed by the federal court and refiled in state court in Douglas County, Wisconsin. The suits, arising out of a 1998 compliance inspection, include claims for alleged violations of federal and state environmental laws at Murphy's Superior, Wisconsin refinery. The suits seek compliance as well as substantial federal and state monetary penalties, which could exceed $100,000. The Company believes it has valid defenses to these allegations and plans a vigorous defense. The enforcement actions are ongoing and while no assurance can be given about the outcome, the Company does not believe that the resolution of these matters will have a material adverse effect on its financial condition. In December 2000, two of the Company's Canadian subsidiaries as plaintiffs filed an action in the Court of Queen's Bench of Alberta seeking a constructive trust over oil and gas leasehold rights to Crown lands in British Columbia. The suit alleges that the defendants acquired the lands after first inappropriately obtaining confidential and proprietary data belonging to the Company and its joint venturer. In January 2001, one of the defendants, representing an undivided 75% interest in the lands in question, settled its portion of the litigation by conveying its interest to the Company and its joint venturer at cost. On February 9, 2001, the remaining defendants, representing the remaining undivided 25% of the lands in question, filed a counterclaim against the Company's two Canadian subsidiaries and one officer individually seeking compensatory damages of C$6.14 billion. The Company believes the counterclaim is without merit and the amount of damages sought is frivolous and the Company does not believe that the ultimate resolution of this suit will have a material adverse effect on its financial condition. 6
Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business and none of which is expected to have a material adverse effect on the Company's financial condition. The ultimate resolution of matters referred to in this Item could have a material adverse effect on the Company's results of operations in a future period. Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of security holders during the fourth quarter of 2000. PART II Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The Company's Common Stock is traded on the New York Stock Exchange and the Toronto Stock Exchange using "MUR" as the trading symbol. There were 3,185 stockholders of record as of December 31, 2000. Information as to high and low market prices per share and dividends per share by quarter for 2000 and 1999 are reported on page F-30 of this Form 10-K report. Item 6. SELECTED FINANCIAL DATA <TABLE> <CAPTION> (Thousands of dollars except per share data) 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- <S> <C> <C> <C> <C> <C> Results of Operations for the Year/1/ Sales and other operating revenues/2/ $ 4,614,341 2,752,083 2,342,644 3,301,542 3,262,418 Net cash provided by continuing operations/2/ 747,751 341,711 297,467 365,825 440,458 Income (loss) from continuing operations 305,561 119,707 (14,394) 132,406 125,956 Income (loss) before cumulative effect of accounting change 305,561 119,707 (14,394) 132,406 137,855 Net income (loss) 296,828 119,707 (14,394) 132,406 137,855 Per Common share - diluted Income (loss) from continuing operations 6.75 2.66 (.32) 2.94 2.80 Income (loss) before cumulative effect of accounting change 6.75 2.66 (.32) 2.94 3.07 Net income (loss) 6.56 2.66 (.32) 2.94 3.07 Cash dividends per Common share 1.45 1.40 1.40 1.35 1.30 Percentage return on Average stockholders' equity 26.4 12.3 (1.3) 12.7 12.2 Average borrowed and invested capital 20.3 9.7 (.6) 10.4 10.4 Average total assets 11.2 5.2 (.6) 6.0 6.2 Capital Expenditures for the Year Exploration and production $ 392,732 295,958 331,647 423,181 373,984 Refining, marketing and transportation 153,750 88,075 55,025 37,483 42,880 Corporate and other 11,415 2,572 2,127 7,367 1,192 ----------- --------- --------- --------- --------- $ 557,897 386,605 388,799 468,031 418,056 =========== ========= ========= ========= ========= Financial Condition at December 31 Current ratio 1.10 1.22 1.15 1.10 1.10 Working capital $ 71,710 105,477 56,616 48,333 56,128 Net property, plant and equipment 2,184,719 1,782,741 1,662,362 1,655,838 1,556,830 Total assets 3,134,353 2,445,508 2,164,419 2,238,319 2,243,786 Long-term debt 524,759 393,164 333,473 205,853 201,828 Stockholders' equity 1,259,560 1,057,172 978,233 1,079,351 1,027,478 Per share 27.96 23.49 21.76 24.04 22.90 Long-term debt - percent of capital employed 29.4 27.1 25.4 16.0 16.4 </TABLE> /1/Includes effects on income of special items in 2000, 1999 and 1998 that are detailed in Management's Discussion and Analysis of Financial Condition and Results of Operations. Also, special items in 1997 and 1996 increased net income by $68, with no per share effect, and $22,124, $.49 a diluted share, respectively. /2/Prior year amounts have been reclassified to conform to 2000 presentation. 7
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Results of Operations The Company reported record net income in 2000 of $296.8 million, $6.56 a diluted share, compared to net income in 1999 of $119.7 million, $2.66 a diluted share. In 1998, the Company lost $14.4 million, $.32 a diluted share. Net income for the three years ended December 31, 2000 included certain special items that resulted in a net charge of $7.2 million, $.16 a diluted share, in 2000; a net benefit of $19.7 million, $.44 a diluted share, in 1999; and a net charge of $57.9 million, $1.29 a diluted share, in 1998. The special items in 2000 included an after-tax charge of $17.8 million, $.39 a diluted share, from write- down of assets determined to be impaired under Statement of Financial Accounting Standards (SFAS) No. 121; a charge of $7.8 million, $.17 a share, for transportation and other disputed contractual items under the Company's concessions in Ecuador; and an after-tax charge of $8.7 million, $.19 a share, for a change in accounting for the Company's unsold crude oil production. Unusual items that increased earnings in 2000 included a $25.6 million settlement of income tax matters, $.56 a share, and a gain on sale of assets of $1.5 million, $.03 a share. The 1999 special items included after-tax gains of $7.5 million, $.17 a diluted share, from sale of assets, and $12.2 million, $.27 a diluted share, primarily from settlements of income taxes and other matters. Special items in 1998 included an after-tax charge of $57.6 million, $1.28 a diluted share, from write-down of assets under SFAS No. 121. 2000 vs. 1999 - Excluding special items, income in 2000 totaled a Company record $304 million, $6.72 a diluted share. The results for 2000 represented a $204 million improvement compared to income of $100 million, $2.22 a diluted share, before special items in 1999. The improvement primarily arose from record earnings from the Company's exploration and production operations, which amounted to $278.3 million in 2000 compared to $121.2 million in 1999. Higher sales prices for both crude oil and natural gas were the principal reasons behind the higher exploration and production earnings. The Company's average worldwide sales price for crude oil and condensate was $25.96 a barrel in 2000 and $17.08 a barrel in 1999. The average sales price of North American natural gas improved from $2.25 a thousand cubic feet (MCF) in 1999 to $3.90 in 2000. Earnings from refining, marketing and transportation operations increased from $14.9 million in 1999 to $54.5 million in 2000. These results improved due to better unit margins in both the United States and the United Kingdom. The costs of corporate activities, which include interest income and expense and corporate overhead not allocated to operating functions, were $28.8 million in 2000, excluding special items, compared to $36.1 million in 1999. The $7.3 million reduction in 2000 was primarily due to lower net interest costs and lower compensation expense for awards under the Company's stock-based incentive plans. 1999 vs. 1998 - Excluding special items, income in 1999 totaled $100 million, $2.22 a share, an increase of $56.5 million from the $43.5 million earned in 1998. The increase in income was primarily attributable to stronger earnings from exploration and production operations, which totaled $121.2 million in 1999 compared to $5.8 million in 1998. This improvement was partially offset by lower earnings from refining, marketing and transportation operations, which earned $14.9 million in 1999, down from $49.2 million earned in 1998. The improvement in exploration and production earnings in 1999 was primarily attributable to an increase of $5.91 a barrel in the average worldwide crude oil sales price, up 53% compared to 1998, and record crude oil production. In addition, the Company's worldwide natural gas sales volume and U.S. natural gas sales prices both increased 4% in 1999. Refining, marketing and transportation operations were adversely affected by the increase in the prices of crude oil and other refinery feedstocks. This segment's decline in earnings was primarily attributable to lower U.S. operating results, as rising crude oil prices squeezed margins throughout most of the year. The costs of corporate and other activities were $36.1 million in 1999 compared to $11.5 million in 1998. The increase in 1999 was principally due to higher net interest costs and higher 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, 2000 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
<TABLE> <CAPTION> (Millions of dollars) 2000 1999 1998 ---- ---- ---- <S> <C> <C> <C> Exploration and production United States $ 63.9 30.3 20.1 Canada 112.3 47.0 2.6 United Kingdom 90.2 37.2 .7 Ecuador 28.9 14.4 2.4 Other (17.0) (7.7) (20.0) -------- ------- ------- 278.3 121.2 5.8 -------- ------- ------- Refining, marketing and transportation United States 23.9 (5.9) 27.7 United Kingdom 23.0 14.0 16.8 Canada 7.6 6.8 4.7 -------- ------- ------- 54.5 14.9 49.2 -------- ------- ------- Corporate and other (28.8) (36.1) (11.5) -------- ------- ------- Income before special items and cumulative effect of accounting change 304.0 100.0 43.5 Settlement of income tax matters 25.6 5.0 - Gain on sale of assets 1.5 7.5 2.9 Impairment of properties (17.8) - (57.6) Gain (loss) on transportation and other disputed contractual items in Ecuador (7.8) 8.2 2.4 Provision for reduction in force - (1.0) - Charge resulting from cancellation of a drilling rig contract - - (4.2) Write-down of crude oil inventories to market value - - (4.2) Settlement of U.K. long-term sales contract - - 2.8 -------- ------- ------- Income (loss) before cumulative effect of accounting change 305.5 119.7 (14.4) Cumulative effect of accounting change (8.7) - - --------- ------- ------- Net income (loss) $ 296.8 119.7 (14.4) ========= ======= ======= </TABLE> Exploration and Production - Earnings from exploration and production operations before special items were a record $278.3 million in 2000, compared to earnings of $121.2 million in 1999 and $5.8 million in 1998. The year over year improvements in 2000 and 1999 were both primarily due to increases in the Company's crude oil sales prices. The Company's 2000 earnings were also favorably affected by higher sales prices for its North American natural gas production. Production of crude oil, condensate and natural gas liquids decreased 1% in 2000, and natural gas sales volumes fell 5% as declines in the U.S. Gulf of Mexico more than offset higher oil and gas sales volumes in Canada. Higher exploration expenses in 2000 partially offset the effects of higher commodity prices. Total oil production in 1999 was a Company record due primarily to production from new fields in the United Kingdom and Canada. In addition, natural gas sales volumes in 1999 were higher than in 1998 in both the United States and Canada. 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-27 and F-28 of this Form 10-K report. Daily production and sales rates and weighted average sales prices are shown on page 9 of the 2000 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
<TABLE> <CAPTION> (Millions of dollars) 2000 1999 1998 ---- ---- ---- <S> <C> <C> <C> United States Crude oil $ 72.4 54.4 35.9 Natural gas 211.4 147.6 136.3 Canada Crude oil 193.9 107.7 57.4 Natural gas 99.0 40.2 25.1 Synthetic oil 91.5 74.8 53.0 United Kingdom Crude oil 214.6 134.7 70.3 Natural gas 7.8 7.7 10.0 Ecuador - crude oil 52.2 36.1 24.2 -------- ------ ----- Total oil and gas revenues $ 942.8 603.2 412.2 ======== ====== ===== </TABLE> The Company's crude oil and gas liquids production averaged 65,259 barrels a day in 2000, 66,083 in 1999 and 59,128 in 1998. Sales of crude oil and gas liquids in 2000 were slightly higher and averaged 65,745 barrels a day. Crude oil and liquids production in the United States declined 21% in 2000, following a 9% increase in 1999. The reduction in 2000 was primarily due to declines from existing fields in the Gulf of Mexico. Oil production in Canada increased 4% in 2000 to a record volume of 31,296 barrels a day. Production at Hibernia rose 2,795 barrels a day due to improved operations. Heavy oil production in western Canada was 1,475 barrels a day higher in 2000 due primarily to an active drilling program in the early part of the year. The Company's share of net production at its synthetic oil operation in Canada was down 2,554 barrels a day in 2000 due to a combination of more downtime for maintenance and a higher net profit royalty caused by higher prices. Before royalties, the Company's synthetic oil production was 10,145 barrels a day in 2000, 11,146 in 1999 and 10,501 in 1998. Production of light oil in Canada decreased 400 barrels a day in 2000. U.K. production increased by 357 barrels a day in 2000 as improved volumes at Mungo/Monan and Schiehallion were almost offset by declines at more mature fields in the North Sea. Production in Ecuador was down 699 barrels a day in 2000 due to transportation constraints. When compared to 1998 oil production, 1999 volumes were up 663 barrels a day in the United States, while production at Hibernia was up 2,212, synthetic oil production was up 497 and U.K. production was 5,127 higher. Production of heavy oil in western Canada fell 577 barrels a day in 1999, light oil declined 351, and production in Ecuador was down 616. The 1999 increase in the United States was due to new production from several small fields in the Gulf of Mexico. Hibernia was improved due to more stabilized operations achieved during the latter half of 1999. Synthetic oil production was up due to higher gross production, partially offset by a higher net profit royalty rate caused by higher prices. Heavy oil production was lower in 1999 because of selective field shut-ins due to low prices during the early part of the year. The improvement in the United Kingdom in 1999 was due to a full year of operations at Mungo/Monan and Schiehallion, both of which commenced production in the third quarter of 1998. The decline in Ecuador production in 1999 was due to pipeline restrictions. Worldwide sales of natural gas averaged 229.4 million cubic feet a day in 2000, 240.4 million in 1999 and 230.9 million in 1998. Sales of natural gas in the United States were 144.8 million cubic feet a day in 2000, 171.8 million in 1999 and 169.5 million in 1998. The 16% reduction in 2000 was due to reduced deliverability from maturing fields in the Gulf of Mexico. The increase in 1999 was mainly due to sales from several new fields in the Gulf of Mexico that more than offset declining production from other fields. Natural gas sales in Canada in 2000 were at record levels for the fifth consecutive year as sales increased 31% to 73.8 million cubic feet a day. Canadian natural gas sales had increased 15% in 1999. The increase in 2000 was primarily due to production from new discoveries in western Canada, plus production obtained through the acquisition of Beau Canada Exploration Ltd. (Beau Canada) in November. Natural gas sales in the United Kingdom were 10.8 million cubic feet a day in 2000, down 1.6 million compared to 1999. U.K. natural gas sales in 1999 were essentially unchanged from 1998 levels. Worldwide crude oil sales prices continued to strengthen through much of 2000 following a solid improvement in 1999. In the United States, Murphy's 2000 average monthly sales prices for crude oil and condensate ranged from $26.12 a barrel to $34.03 a barrel, and averaged $30.38 for the year, 68% above the average 1999 price of $18.09. In Canada, the average sales price for light oil was $27.68 a barrel in 2000, an increase of 63%. Heavy oil prices averaged $17.83 a barrel, up 40% compared to a year ago. The average sales price for synthetic oil in 2000 was $29.62, up 59% from 1999. The sales price for crude oil from the Hibernia field increased 42% to $27.16 a barrel. U.K. sales prices averaged 10
54% higher in 2000 at $27.78 a barrel. Sales prices in Ecuador were $22.01 a barrel in 2000, up 53% from a year earlier. U.S. oil prices increased 40% in 1999 compared to 1998. In Canada, crude oil prices in 1999 were up 41% for light oil, 95% for heavy oil, 36% for synthetic oil, and 62% for Hibernia. Oil prices in the United Kingdom were up 44% in 1999, and prices in Ecuador were up 68%. Worldwide oil prices showed signs of weakening in late 2000 and into early 2001. Although the Organization of Petroleum Exporting Countries (OPEC) announced a production cut effective February 1, 2001, the Company can make no assurances that oil prices will remain at or near year-end 2000 prices of about $26.00 a barrel for West Texas Intermediate grade crude oil. North American natural gas sales prices strengthened as 2000 progressed due to supply being short of demand. A combination of a hotter than normal summer and a colder than normal early winter near the end of 2000 in the United States strained an already below-normal level of gas storage throughout the country. Average monthly natural gas sales prices in the United States in 2000 ranged from $2.48 an MCF in January to $6.68 in December. For the year, U.S. sales prices increased 71% and averaged $4.01 an MCF compared to $2.34 in 1999. The average price for natural gas sold in Canada during 2000 increased 87% to $3.67 an MCF, while prices in the United Kingdom increased 8% to $1.81. Average U.S. natural gas sales prices were up 4% in 1999, and prices were up in Canada by 40% as Canadian natural gas sales prices moved closer to parity with U.S. prices during the year. The average U.K. gas sales price in 1999 fell 25% mainly as a result of a contractual price basis adjustment at the Company's primary North Sea gas field. Based on 2000 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 $16.2 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 expenses were $181.9 million in 2000, $162.1 million in 1999 and $167.3 million in 1998. These amounts are shown by major operating area on pages F-27 and F-28 of this Form 10-K report. Cost per equivalent barrel during the last three years were as follows. <TABLE> <CAPTION> (Dollars per equivalent barrel) 2000 1999 1998 ---- ---- ---- <S> <C> <C> <C> United States $ 3.72 2.98 3.66 Canada Excluding synthetic oil 4.24 3.99 3.91 Synthetic oil 13.06 9.09 8.99 United Kingdom 3.46 3.73 5.60 Ecuador 6.65 5.10 4.28 Worldwide - excluding synthetic oil 4.05 3.62 4.18 </TABLE> The increase in the cost per equivalent barrel in the United States in 2000 was attributable to a combination of lower production and higher well servicing costs. The 2000 increase in Canada, excluding synthetic oil, was due to an increase in well servicing costs at heavy oil properties offset in part by the effect of higher production at Hibernia, where production expenses are lower than in western Canada. The increase in the cost per equivalent barrel for Canadian synthetic oil in 2000 was due to lower gross production volumes and an increase in royalty barrels caused by higher oil prices. Based on the Company's interest in Syncrude's gross production, cost per barrel increased 21% in 2000. A lower unit cost in the United Kingdom in 2000 was due to a favorable impact from higher production at the lower-cost Mungo/Monan and Schiehallion fields. Higher cost per barrel in Ecuador in 2000 was attributable to both lower production and higher overall operating expenses. The decrease in U.S. production cost per equivalent barrel in 1999 was attributable to lower well servicing costs combined with higher production volumes. The increase in Canada in 1999, excluding synthetic oil, was caused by higher well servicing costs at heavy oil properties. The increase in the Canadian synthetic oil unit rate was due to an increase in royalty barrels caused by higher sales prices. The decrease in the U.K. rate was due to higher production from the lower-cost Mungo/Monan and Schiehallion fields. The higher cost in Ecuador in 1999 was caused by higher field operating costs combined with lower production during the year. Exploration expenses for each of the last three years are shown in total in the following table, and amounts are reported by major operating area on pages F-27 and F-28 of this Form 10-K report. Certain of the expenses are included in the capital expenditure totals for exploration and production activities. 11
<TABLE> <CAPTION> (Millions of dollars) 2000 1999 1998 ---- ---- ---- <S> <C> <C> <C> Exploratory expenditures charged against income Dry hole costs $ 66.0 32.4 31.5 Geological and geophysical costs 36.3 18.7 17.0 Other costs 9.2 8.5 6.6 -------- ------ ------- 111.5 59.6 55.1 Undeveloped lease amortization 14.1 11.0 10.5 -------- ------ ------- Total exploration expenses $ 125.6 70.6 65.6 ======== ====== ======= </TABLE> Depreciation, depletion and amortization related to exploration and production operations totaled $169.2 million in 2000, $166.9 million in 1999 and $163.6 million in 1998. The increases in both 2000 and 1999 were due to higher production from the Hibernia field, offshore eastern Canada. Additionally, 2000 includes higher depreciation rates per unit on production from fields acquired from Beau Canada. Refining, Marketing and Transportation - Earnings from refining, marketing and transportation operations before special items were $54.5 million in 2000, $14.9 million in 1999 and $49.2 million in 1998. Operations in the United States earned $23.9 million in 2000 compared to a loss of $5.9 million in 1999, as product sales realizations increased more than the costs of crude oil and other refinery feedstocks. U.S. operations earned $27.7 million in 1998. The decline in 1999 was due to the inability to fully recover higher costs of crude oil through increases in average product sales prices. Operations in the United Kingdom earned $23 million in 2000, $14 million in 1999 and $16.8 million in 1998. The improvement in 2000 was also caused by a larger increase in the sales realizations for finished products than for the costs of refining feedstocks. Canadian operations contributed $7.6 million to 2000 earnings compared to $6.8 million in 1999 and $4.7 million in 1998. Unit margins (sales realizations less costs of crude oil, other feedstocks, refining and transportation to point of sale) averaged $1.91 a barrel in the United States in 2000, $.66 in 1999 and $1.45 in 1998. U.S. product sales totaled a record 149,469 barrels a day in 2000, up 18% following an 8% decline in 1999. The increase in 2000 was attributable to a combination of record crude oil throughputs at the Company's U.S. refineries plus continued expansion of retail gasoline operations at Wal-Mart stores. The decline in sales volumes in 1999 was primarily due to a turnaround at the Meraux refinery early in the year. Unit margins in the United Kingdom averaged $4.69 a barrel in 2000, $3.38 in 1999 and $2.81 in 1998. Sales of petroleum products were down 7% in 2000 following an 11% decrease in 1999. The volume decline in 2000 was attributable to lower consumer demand in the United Kingdom caused by the large increase in product prices during the year. The decline in 1999 was due to lower sales in the cargo market. Although unit margins improved in 2000, the Company's branded outlets still face competition from other motor fuel marketers. Unit margins have softened in early 2001, and the Company was experiencing weaker financial results in its U.K. downstream operations. Based on sales volumes for 2000 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 $17.5 million. The effect of these unit margin fluctuations on consolidated net income cannot be measured because operating results of the Company's exploration and production segments could be affected differently. The improvement in the Company's Canadian downstream operating results in 2000 was due to higher pipeline throughputs after the acquisition of the minority interest in the Manito pipeline system in mid-year. Higher earnings in 1999 were attributable to improved operating results from crude oil trading and pipeline operations. The Company entered into an agreement to sell its Canadian pipeline and trucking operation in 2001. Special Items - Net income for the last three years included certain special items reviewed in the following paragraphs. The effects of special items on quarterly results for 2000 and 1999 are presented on page F-30 of this Form 10-K report. . Settlement of income tax matters - Gains of $15.5 million, $10.1 million and $5 million for settlement of U.S. income tax matters were recorded in the third quarter of 2000, the fourth quarter of 2000 and the fourth quarter of 1999, respectively. 12
. Gain on sale of assets - After-tax gains on sale of assets included $1.5 million recorded in the second quarter of 2000 from sale of U.S. corporate assets, $6.3 million and $1.2 million recorded in the third and fourth quarters, respectively, of 1999 from sale of U.S. service stations, and $2.9 million recorded in the fourth quarter of 1998 from sale of a U.K. service station. . Impairment of properties - After-tax provisions of $13.6 million, $4.2 million and $57.6 million were recorded in the third quarter of 2000, the fourth quarter of 2000 and the fourth quarter of 1998, respectively, for the write-down of assets determined to be impaired. (See Note D to the consolidated financial statements.) . Gain (loss) on transportation and other disputed contractual items in Ecuador - A loss of $7.8 million was recorded in the fourth quarter of 2000, and gains of $8.2 million, $1.4 million and $1 million were recorded in the fourth quarter of 1999, the second quarter of 1998 and the fourth quarter of 1998, respectively, related to transportation and other contractual disputes under the Company's concessions in Ecuador. . Provision for reduction in force - An after-tax charge of $1 million for a reduction in force program was recorded in the first quarter of 1999. (See Note G 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 market conditions allowed a more efficient and modern rig to be obtained, thus 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. . Settlement 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 settlement of a U.K. long-term sales contract. . Cumulative effect of accounting change - An after-tax charge of $8.7 million was recorded in the first quarter of 2000 to carry the Company's unsold crude oil production at cost rather than at market value as in the past. (See Note B to the consolidated financial statements.) The income (loss) effects of special items for each of the three years ended December 31, 2000 are summarized by segment in the following table. <TABLE> <CAPTION> (Millions of dollars) 2000 1999 1998 ---- ---- ---- <S> <C> <C> <C> Exploration and production United States $ (13.6) 5.0 (19.4) Canada (4.2) - (10.1) United Kingdom - - (14.0) Ecuador (7.8) 8.2 2.4 Other - - (15.1) ------- ------ ------- (25.6) 13.2 (56.2) ------- ------ ------- Refining, marketing and transportation United States - 7.5 - United Kingdom - - .5 Canada - - (2.2) ------- ------ ------- - 7.5 (1.7) ------- ------ ------- Corporate and other 27.1 (1.0) - ------- ------ ------- Cumulative effect of accounting change (8.7) - - ------- ------ ------- Total income (loss) from special items $ (7.2) 19.7 (57.9) ======= ====== ======= </TABLE> 13
Capital Expenditures As shown in the selected financial information on page 7 of this Form 10-K report, capital expenditures, including discretionary exploration expenditures, were $557.9 million in 2000 compared to $386.6 million in 1999 and $388.8 million in 1998. These amounts included $111.5 million, $59.6 million and $55.1 million of exploration costs that were expensed. Capital expenditures for exploration and production activities totaled $392.7 million in 2000, 70% of the Company's total capital expenditures for the year. Exploration and production capital expenditures in 2000 included $44.3 million for acquisition of undeveloped leases, $4.4 million for acquisition of proved oil and gas properties, $156.7 million for exploration activities, and $187.3 million for development projects. Development expenditures included $60.7 million for the Terra Nova oil field, offshore Newfoundland; $18.5 million for synthetic oil operations in Canada; and $44.6 million for heavy oil and natural gas projects in western Canada. Exploration and production capital expenditures are shown by major operating area on page F-26 of this Form 10-K report. Amounts shown under "Other" in 2000 included $18.4 million for exploration costs in Malaysia, including costs to drill a shallow-water discovery on Block SK 309, offshore Sarawak. Refining, marketing and transportation expenditures, detailed in the following table, were 28% of total capital expenditures in 2000. (Millions of dollars) 2000 1999 1998 ---- ---- ---- Refining United States $ 19.2 17.4 27.0 United Kingdom 4.3 7.0 .7 ------ ------ ------ Total refining 23.5 24.4 27.7 ------ ------ ------ Marketing United States 92.8 58.7 16.7 United Kingdom 8.1 4.4 6.1 ------ ------ ------ Total marketing 100.9 63.1 22.8 ------ ------ ------ Transportation United States - .3 1.9 Canada 29.4 .3 2.6 ------ ------ ------ Total transportation 29.4 .6 4.5 ------ ------ ------ Total $153.8 88.1 55.0 ====== ====== ====== U.S. and U.K. refining expenditures during the three years 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 U.S. motor fuel specifications. Marketing expenditures in the United States primarily included the costs of new stations built on land leased from Wal-Mart, and improvements and normal replacements at existing stations and terminals. U.K. marketing expenditures in 2000 were primarily for redevelopment of shops and station purchases; expenditures in 1999 and 1998 were primarily for improvements and normal replacements at existing stations and terminals. Capital expenditures for Canadian transportation in 2000 primarily consisted of the mid-year acquisition of the minority interest in the Manito pipeline system. Cash Flows Cash provided by operating activities was $747.8 million in 2000, $341.7 million in 1999 and $297.5 million in 1998. Special items decreased cash flow from operations by $2.7 million in 2000 and $6.3 million in 1998, but increased cash by $18.9 million in 1999. Changes in operating working capital other than cash and cash equivalents provided cash of $66 million in 2000, but required cash of $35.2 million and $3.8 million in 1999 and 1998, respectively. Cash provided by operating activities was further reduced by expenditures for refinery turnarounds and abandonment of oil and gas properties totaling $16.6 million in 2000, $44.1 million in 1999 and $24.6 million in 1998. Cash proceeds from property sales were $20.7 million in 2000, $40.9 million in 1999 and $9.5 million in 1998. Borrowings under notes payable provided $175 million of cash in 2000, $247.8 million in 1999 and $161.3 million in 1998. 14
Property additions and dry hole costs required $512.3 million of cash in 2000, $359.4 million in 1999 and $365.2 million in 1998. Cash outlays for debt repayment during the three years included $130.5 million in 2000, $195.9 million in 1999 and $34.5 million in 1998. The acquisition of Beau Canada in November 2000 utilized $127.5 million of cash. Cash used for dividends to stockholders was $65.3 million in 2000, $63 million in 1999 and $62.9 million in 1998. Financial Condition Year-end working capital totaled $71.7 million in 2000, $105.5 million in 1999 and $56.6 million in 1998. The current level of working capital does not fully reflect the Company's liquidity position as the carrying values for inventories under last-in first-out accounting were $124 million below current costs at December 31, 2000. Cash and cash equivalents at the end of 2000 totaled $132.7 million compared to $34.1 million a year ago and $28.3 million at the end of 1998. Long-term debt increased $131.6 million during 2000 to $524.8 million at the end of the year, 29.4% of total capital employed, and included $126.4 million of nonrecourse debt incurred in connection with the acquisition and development of Hibernia. The increase in long-term debt in 2000 was attributable to the acquisition of Beau Canada. Long-term debt totaled $393.2 million at the end of 1999 compared to $333.5 million at December 31, 1998. Stockholders' equity was $1.3 billion at the end of 2000 compared to $1.1 billion a year ago and $1 billion at the end of 1998. A summary of transactions in 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 expenditures, but maintains lines of credit with banks and borrows as necessary to meet spending requirements. Current financing arrangements are set forth in Note E to the consolidated financial statements. The Company does not expect any problem in meeting future requirements for funds. Murphy had commitments of $353 million for capital projects in progress at December 31, 2000, including $176 million related to a clean fuels expansion project at the Meraux refinery and $67 million related to the Company's multiyear contract for a semisubmersible deepwater drilling rig. Certain costs committed under the rig contract will be charged to Murphy's partners when future deepwater wells are drilled. 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, an environmental liability is recorded when such an obligation is probable and the cost can be reasonably estimated. If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used. Recorded liabilities are reviewed quarterly. Actual cash expenditures often occur one or more years after a liability is recognized. The Company's 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 (EPA) 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 15
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 rate share of costs attributable to nonparticipating PRPs or indications of additional responsibility by the Company. Lawsuits filed against Murphy by the U.S. Government and the State of Wisconsin are discussed under the caption "Legal Proceedings" on page 6 of this Form 10-K report. There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. Such expenditures could have a material adverse effect on 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, 2000. The Company's refineries also incur costs to handle and dispose of hazardous waste and other chemical substances. These costs are expensed as incurred and amounted to $2.9 million in 2000. In addition to these expenses, Murphy allocates a portion of its capital expenditure program to comply with environmental laws and regulations. Such capital expenditures were approximately $26 million in 2000 and are projected to be $86 million in 2001. Other Matters Impact of inflation - General inflation was moderate during the last three years in most countries where the Company operates; however, the Company's revenues and capital and operating costs are influenced to a larger extent by specific price changes in the oil and gas and allied industries than by changes in general inflation. Crude oil and petroleum product prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC production levels and/or attitudes of traders concerning supply and demand in the near future. Natural gas prices are affected by supply and demand, which to a significant extent are affected by the weather and by the fact that delivery of gas is generally restricted to specific geographic areas. If crude oil and natural gas sales prices remain strong, the Company believes that the future prices for oil field goods and services could be adversely affected. Accounting matters - The Financial Accounting Standards Board (FASB) issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," in 1998. This statement established accounting and reporting standards for derivative instruments and hedging activities. Subsequent to the issuance of SFAS No. 133, the FASB received many requests to review and clarify certain implementation issues. In June 2000, the FASB issued SFAS No. 138, which amended certain provisions of SFAS No. 133. Effective January 1, 2001, 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. Changes in a derivative's fair value for a qualifying hedge of a forecasted transactions will be deferred and recorded as a component of Other Accumulated Comprehensive Income in the Consolidated Balance Sheet until the forecasted transaction occurs, at which time the derivative's value will be recognized in earnings. Ineffective portions of a hedging derivative's change in fair value will be immediately recognized in earnings. Transition adjustments resulting from adopting this statement will be reported in net income or other comprehensive income, as appropriate, as the cumulative effect of an accounting change. As described under the heading "Quantitative and Qualitative Disclosures About Market Risk" on Page 17 of this Form 10-K report, the Company makes limited use of derivative instruments to hedge specific market risks. The Company has determined that the adoption of SFAS 133 will increase other comprehensive income by approximately $4 million and the overall effect on net income from adoption of this standard will not be significant. As described in Note B to the consolidated financial statements, the Company has adopted a change in accounting for unsold crude oil production effective January 1, 2000, and also has retroactively applied two consensuses of the FASB Emerging Issue Task Force to 2000 and all prior years presented. 16
Outlook Prices for the Company's primary products are often quite volatile. During 1999 and most of 2000, increased worldwide demand and disciplined management of supply by the world's producers - primarily by members of OPEC - led to stronger oil prices. During late 2000 and early 2001, crude oil sales prices weakened slightly. In mid-January 2001, OPEC announced a reduction in crude oil production beginning February 1, 2001 and light sweet crude oil for March delivery sold for more than $31 a barrel at that date. The Company can give no assurance that the price of crude oil will remain at this high level during the remainder of 2001 and beyond. Due to colder than normal weather across much of North America during the early winter of 2000-2001, the price of natural gas remained well above its normal trading range in January 2001. The Company can give no assurance that the price of natural gas will remain at or above its normal trading range in the future. The Company's U.K. refining and marketing operations were experiencing weaker unit margins in early 2001. In such a volatile operating environment, constant reassessment of spending plans is required. The Company's capital expenditure budget for 2001 was prepared during the fall of 2000 and provides for expenditures of $692 million. Of this amount, $518 million or 75%, is allocated for exploration and production. Geographically, 39% of the exploration and production budget is allocated to the United States, including $84 million for development of deepwater projects in the Gulf of Mexico; another 43% is allocated to Canada, including $29 million for continued development of the Terra Nova oil field, which is currently scheduled for start-up late in 2001, and $22 million for further expansion of synthetic oil operations; 7% is allocated to the United Kingdom; 3% is allocated to Ecuador; and 8% is allocated to other foreign operations, which primarily includes Malaysia. Planned refining, marketing and transportation capital expenditures for 2001 are $168 million, including $145 million in the United States, $20 million in the United Kingdom and $3 million in Canada. U.S. amounts include funds to build additional stations at Wal-Mart sites, as well as early spending for "green fuel" projects at the Meraux refinery. Capital and other expenditures are under constant review and planned capital expenditures may be adjusted to reflect changes in estimated cash flow during 2001. 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 report on file with the U.S. Securities and Exchange Commission. Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note A to the consolidated financial statements, Murphy makes limited use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions. At December 31, 2000, 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. These 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, 2000, the interest rate to be received by the Company averaged 6.72%. 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 K to the consolidated financial statements, the estimated fair value of these interest rate swaps was a loss of $2 million at December 31, 2000. At December 31, 2000, 20% of the Company's debt had variable interest rates and 12% was denominated in Canadian dollars. Based on debt outstanding at December 31, 2000, a 10% increase in variable interest rates would reduce the 17
Company's interest expense by $.1 million in 2001 after a $.7 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 versus the U.S. dollar would increase interest expense in 2001 by $.2 million and increase current maturities of long-term debt by $.8 million for debt denominated in Canadian dollars. At December 31, 2000, Murphy was a party to natural gas price swap agreements for a total notional volume of 7 million MMBTU that are intended to reduce a portion of the financial exposure of its Meraux, Louisiana refinery to fluctuations in the price of natural gas purchased for fuel in 2002 through 2004. In each month of settlement, the swaps require Murphy to pay an average natural gas price of $2.61 an MMBTU and to receive the average NYMEX Henry Hub price for the final three trading days of the month. At December 31, 2000, the estimated fair value of these agreements was a gain of $6.2 million; a 10% fluctuation in the average NYMEX Henry Hub price of natural gas would have changed the estimated year-end fair value of these swaps by $2.1 million. At December 31, 2000, Murphy was also a party to certain natural gas swap agreements for a total notional volume of 20,000 gigajoules (GJ) a day through October 2001 that are intended to reduce a portion of the financial exposure of its Canadian natural gas production to changes in natural gas sales prices. In each month, the swaps require Murphy to pay the AECO "C" index price and to receive an average of C$2.47 per GJ. The Company also has a natural gas swap agreement for the purchase of 10,000 GJ per day through October 2001 that requires Murphy to pay C$5.64 per GJ and to receive based on the AECO "C" index. At December 31, 2000, the estimated net fair value of these agreements was a liability of $18.3 million; a 10% fluctuation in the average price of the AECO "C" index would have changed the estimated year-end fair value of these swaps by $1.7 million. Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Information required by this item appears on pages F-1 through F-30, which follow page 21 of this Form 10-K report. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None 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 9, 2001 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 9, 2001 under the captions "Compensation of Directors," "Executive Compensation," "Option Exercises and Fiscal Year-End Values," "Option Grants," "Compensation Committee Report for 2000," "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 9, 2001 under the captions "Security Ownership of Certain Beneficial Owners" and "Security Ownership of Management." 18
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 9, 2001 under the caption "Compensation Committee Interlocks and Insider Participation." 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-24 Supplemental Quarterly Information (unaudited) F-30 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 (*), that are to be filed by an amendment as indicated by pound sign (#), or that are incorporated by reference. Exhibits other than those listed have been omitted since they either are not required or are not applicable. <TABLE> <CAPTION> Exhibit No. Incorporated by Reference to - ------- ------------------------------------------------ <S> <C> <C> 3.1 Certificate of Incorporation of Murphy Oil Corporation as of Exhibit 3.1 of Murphy's Form 10-K report for the September 25, 1986 year ended December 31, 1996 *3.2 By-Laws of Murphy Oil Corporation as amended effective February 7, 2001 4 Instruments Defining the Rights of Security Holders. Murphy is party to several long-term debt instruments in addition to the ones in Exhibits 4.1 and 4.2, 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 certain Exhibit 4.1 of Murphy's Form 10-K report for the subsidiaries and the Chase Manhattan Bank et al as of November 13, year ended December 31, 1997 1997 </TABLE> 19
<TABLE> <S> <C> <C> 4.2 Form of Indenture and Form of Supplemental Indenture between Murphy Exhibits 4.1 and 4.2 of Murphy's Form 8-K report Oil Corporation and SunTrust Bank, Nashville, N.A., as Trustee filed April 29, 1999 under the Securities Exchange Act of 1934 4.3 Rights Agreement dated as of December 6, 1989 between Murphy Oil Exhibit 4.3 of Murphy's Form 10-K report for Corporation and Harris Trust Company of New York, as Rights the year ended December 31, 1999 Agent 4.4 Amendment No. 1 dated as of April 6, 1998 to Rights Agreement dated Exhibit 3 of Murphy's Form 8-A/A, Amendment No. 1, as of December 6, 1989 between Murphy Oil Corporation and Harris filed April 14, 1998 under the Securities Exchange Trust Company of New York, as Rights Agent Act of 1934 4.5 Amendment No. 2 dated as of April 15, 1999 to Rights Agreement dated Exhibit 4 of Murphy's Form 8-A/A, Amendment No. 2, as of December 6, 1989 between Murphy Oil Corporation and Harris filed April 19, 1999 under the Securities Exchange Trust Company of New York, as Rights Agent Act of 1934 10.1 1987 Management Incentive Plan as amended February 7, 1990 Exhibit 10.1 of Murphy's Form 10-K report for the retroactive to February 3, 1988 year ended December 31, 1999 10.2 1992 Stock Incentive Plan as amended May 14, 1997 Exhibit 10.2 of Murphy's Form 10-Q report for the quarterly period ended June 30, 1997 10.3 Employee Stock Purchase Plan as amended May 10, 2000 Exhibit 99.01 of Murphy's Form S-8 Registration Statement filed August 4, 2000 under the Securities Act of 1933 *13 2000 Annual Report to Security Holders including Narrative to Graphic and Image Material as an appendix *21 Subsidiaries of the Registrant *23 Independent Auditors' Consent *99.1 Undertakings #99.2 Form 11-K, Annual Report for the fiscal year ended December 31, 2000 To be filed as an amendment to this Form 10-K covering the Thrift Plan for Employees of Murphy Oil Corporation report not later than 180 days after December 31, 2000 #99.3 Form 11-K, Annual Report for the fiscal year ended December 31, To be filed as an amendment to this Form 10-K 2000 covering the Thrift Plan for Employees of Murphy Oil USA, report not later than 180 days after December 31, Inc. Represented by United Steelworkers of America, AFL-CIO, 2000 Local No. 8363 #99.4 Form 11-K, Annual Report for the fiscal year ended December 31, 2000 To be filed as an amendment to this Form 10-K covering the Thrift Plan for Employees of Murphy Oil USA, Inc. report not later than 180 days after December 31, Represented by International Union of Operating Engineers, 2000 AFL-CIO, Local No. 305 </TABLE> (b) Reports on Form 8-K No reports on Form 8-K were filed during the quarter ended December 31, 2000. 20
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 /s/ CLAIBORNE P. DEMING Date: March 22, 2001 -------------------------------------- --------------------- Claiborne P. Deming, President Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 22, 2001 by the following persons on behalf of the registrant and in the capacities indicated. /s/ R. MADISON MURPHY /s/ WILLIAM C. NOLAN JR. - ---------------------------------------- ----------------------------------- R. Madison Murphy, Chairman and Director William C. Nolan Jr., Director /s/ CLAIBORNE P. DEMING /s/ WILLIAM L. ROSOFF - ---------------------------------------- ----------------------------------- Claiborne P. Deming, President and Chief William L. Rosoff, Director Executive Officer and Director (Principal Executive Officer) /s/ B. R. R. BUTLER /s/ DAVID J. H. SMITH - ---------------------------------------- ----------------------------------- B. R. R. Butler, Director David J. H. Smith, Director /s/ GEORGE S. DEMBROSKI /s/ CAROLINE G. THEUS - ---------------------------------------- ----------------------------------- George S. Dembroski, Director Caroline G. Theus, Director /s/ H. RODES HART /s/ STEVEN A. COSSE - ---------------------------------------- ----------------------------------- H. Rodes Hart, Director Steven A. Cosse, Senior Vice President and General Counsel (Principal Financial Officer) /s/ ROBERT A. HERMES /s/ JOHN W. ECKART - ---------------------------------------- ----------------------------------- Robert A. Hermes, Director John W. Eckart, Controller (Principal Accounting Officer) /s/ MICHAEL W. MURPHY - ---------------------------------------- Michael W. Murphy, Director 21
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 U.S. 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 auditing standards generally accepted in the United States of America 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, 2000 and 1999, 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, 2000. 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 auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our 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, 2000 and 1999, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America. As discussed in Note B to the consolidated financial statements, effective January 1, 2000, the Company changed its method of accounting for crude oil inventories. Shreveport, Louisiana /s/ KPMG LLP January 26, 2001 F-1
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME <TABLE> <CAPTION> Years Ended December 31 (Thousands of dollars except per share amounts) 2000 1999* 1998* ---- ---- ---- <S> <C> <C> <C> Revenues Crude oil and natural gas sales $ 751,498 470,643 324,882 Petroleum product sales 2,731,988 1,515,537 1,312,727 Crude oil trading sales 1,041,524 705,969 638,106 Other operating revenues 89,331 59,934 66,929 Interest and other nonoperating revenues 24,824 4,358 4,378 ------------ ------------ ------------ Total revenues 4,639,165 2,756,441 2,347,022 ------------ ------------ ------------ Costs and Expenses Crude oil, products and related operating expenses 3,704,936 2,198,701 1,927,325 Exploration expenses, including undeveloped lease amortization 125,629 70,557 65,582 Selling and general expenses 85,474 81,817 61,363 Depreciation, depletion and amortization 213,539 205,077 203,163 Impairment of properties 27,916 -- 80,127 Charge resulting from cancellation of a drilling rig contract -- -- 7,255 Provision for reduction in force -- 1,513 -- Interest expense 29,936 28,139 18,090 Interest capitalized (13,599) (7,865) (7,606) ------------ ------------ ------------ Total costs and expenses 4,173,831 2,577,939 2,355,299 ------------ ------------ ------------ Income (loss) before income taxes and cumulative effect of accounting change 465,334 178,502 (8,277) Income tax expense 159,773 58,795 6,117 ------------ ------------ ------------ Income (loss) before cumulative effect of accounting change 305,561 119,707 (14,394) Cumulative effect of accounting change, net of tax (Note B) (8,733) -- -- ------------ ------------ ------------ Net Income (Loss) $ 296,828 119,707 (14,394) ============ ============ ============ Income (Loss) per Common Share - Basic Before cumulative effect of accounting change $ 6.78 2.66 (.32) Cumulative effect of accounting change (.19) -- -- ------------ ------------ ------------ Net Income (Loss) - Basic 6.59 2.66 (.32) ============ ============ ============ Income (Loss) per Common Share - Diluted Before cumulative effect of accounting change $ 6.75 2.66 (.32) Cumulative effect of accounting change (.19) -- -- ------------ ------------ ------------ Net Income (Loss) - Diluted 6.56 2.66 (.32) ============ ============ ============ Average Common shares outstanding - basic 45,031,665 44,970,457 44,955,679 Average Common shares outstanding - diluted 45,239,706 45,030,225 44,955,679 </TABLE> MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME <TABLE> <CAPTION> Years Ended December 31 (Thousands of dollars) 2000 1999 1998 ---- ---- ---- <S> <C> <C> <C> Net income (loss) $ 296,828 119,707 (14,394) Other comprehensive income (loss) - net gain (loss) from foreign currency translation (33,282) 18,536 (24,411) ------------ ------------ ------------ Comprehensive Income (Loss) $ 263,546 138,243 (38,805) ============ ============ ============ </TABLE> *Reclassified to conform to 2000 presentation. See notes to consolidated financial statements, page F-6. F-2
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED BALANCE SHEETS <TABLE> <CAPTION> December 31 (Thousands of dollars) 2000 1999 ---- ---- <S> <C> <C> Assets Current assets Cash and cash equivalents $ 132,701 34,132 Accounts receivable, less allowance for doubtful accounts of $10,208 in 2000 and $8,298 in 1999 469,616 357,472 Inventories, at lower of cost or market Crude oil and blend stocks 47,875 61,853 Finished products 68,464 50,572 Materials and supplies 48,416 39,218 Prepaid expenses 23,949 28,145 Deferred income taxes 25,916 21,720 ----------- ----------- Total current assets 816,937 593,112 Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $3,144,369 in 2000 and $3,007,578 in 1999 2,184,719 1,782,741 Goodwill, net 48,396 -- Deferred charges and other assets 84,301 69,655 ----------- ----------- Total assets $ 3,134,353 2,445,508 =========== =========== Liabilities and Stockholders' Equity Current liabilities Current maturities of long-term debt $ 37,242 71 Accounts payable 528,416 334,420 Withholdings and collections due governmental agencies 65,262 65,706 Other accrued liabilities 45,964 49,143 Income taxes 68,343 38,295 ----------- ----------- Total current liabilities 745,227 487,635 Notes payable 398,375 248,569 Nonrecourse debt of a subsidiary 126,384 144,595 Deferred income taxes 229,968 154,109 Reserve for dismantlement costs 160,049 158,377 Reserve for major repairs 34,302 22,099 Deferred credits and other liabilities 180,488 172,952 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 514,474 512,488 Retained earnings 833,490 601,956 Accumulated other comprehensive loss - foreign currency translation (38,266) (4,984) Unamortized restricted stock awards (1,410) (2,328) Treasury stock (97,503) (98,735) ----------- ----------- Total stockholders' equity 1,259,560 1,057,172 ----------- ----------- Total liabilities and stockholders' equity $ 3,134,353 2,445,508 =========== =========== </TABLE> See notes to consolidated financial statements, page F-6. F-3
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS <TABLE> <CAPTION> Years Ended December 31 (Thousands of dollars) 2000 1999* 1998* ---- ---- ---- <S> <C> <C> <C> Operating Activities Income (loss) before cumulative effect of accounting change $ 305,561 119,707 (14,394) Adjustments to reconcile above income (loss) to net cash provided by operating activities Depreciation, depletion and amortization 213,539 205,077 203,163 Impairment of properties 27,916 -- 80,127 Provisions for major repairs 22,761 18,721 20,420 Expenditures for major repairs and dismantlement costs (16,603) (44,096) (24,582) Dry hole costs 65,987 32,422 31,504 Amortization of undeveloped leases 14,076 10,968 10,454 Deferred and noncurrent income tax charges (credits) 63,431 38,027 (937) Pretax gains from disposition of assets (4,010) (11,940) (3,857) Net (increase) decrease in noncash operating working capital excluding acquisition of Beau Canada Exploration Ltd. 66,002 (35,159) (3,810) Cumulative effect of accounting change on working capital (11,170) -- -- Other operating activities - net 261 7,984 (621) --------- --------- --------- Net cash provided by operating activities 747,751 341,711 297,467 --------- --------- --------- Investing Activities Property additions and dry hole costs (512,331) (359,438) (365,175) Acquisition of Beau Canada Exploration Ltd., net of cash acquired (127,476) -- -- Proceeds from sale of property, plant and equipment 20,705 40,871 9,463 Other investing activities - net 391 (3,532) (1,767) --------- --------- --------- Net cash required by investing activities (618,711) (322,099) (357,479) --------- --------- --------- Financing Activities Additions to notes payable 175,000 247,776 161,342 Reductions of notes payable (124,254) (190,806) (218) Additions to nonrecourse debt of a subsidiary -- -- 240 Reductions of nonrecourse debt of a subsidiary (6,207) (5,120) (34,234) Cash dividends paid (65,294) (62,950) (62,939) Other financing activities - net (4,125) (1,742) 552 --------- --------- --------- Net cash provided (required) by financing activities (24,880) (12,842) 64,743 --------- --------- --------- Effect of exchange rate changes on cash and cash equivalents (5,591) (909) (748) --------- --------- --------- Net increase in cash and cash equivalents 98,569 5,861 3,983 Cash and cash equivalents at January 1 34,132 28,271 24,288 --------- --------- --------- Cash and cash equivalents at December 31 $ 132,701 34,132 28,271 ========= ========= ========= </TABLE> *Reclassified to conform to 2000 presentation. See notes to consolidated financial statements, page F-6. F-4
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY <TABLE> <CAPTION> Years Ended December 31 (Thousands of dollars) 2000 1999 1998 ---- ---- ---- <S> <C> <C> <C> 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 each year 48,775 48,775 48,775 ----------- ----------- ----------- Capital in Excess of Par Value Balance at beginning of year 512,488 510,116 509,615 Exercise of stock options 1,749 797 103 Restricted stock transactions (202) 1,344 142 Sale of stock under employee stock purchase plans 439 231 256 ----------- ----------- ----------- Balance at end of year 514,474 512,488 510,116 ----------- ----------- ----------- Retained Earnings Balance at beginning of year 601,956 545,199 622,532 Net income (loss) for the year 296,828 119,707 (14,394) Cash dividends - $1.45 a share in 2000, $1.40 a share in 1999 and 1998 (65,294) (62,950) (62,939) ----------- ----------- ----------- Balance at end of year 833,490 601,956 545,199 ----------- ----------- ----------- Accumulated Other Comprehensive Income (Loss) - Foreign Currency Translation Balance at beginning of year (4,984) (23,520) 891 Translation gains (losses) during the year (33,282) 18,536 (24,411) ----------- ----------- ----------- Balance at end of year (38,266) (4,984) (23,520) ----------- ----------- ----------- Unamortized Restricted Stock Awards Balance at beginning of year (2,328) (2,361) (944) Stock awards -- -- (3,238) Amortization, forfeitures and changes in price of Common Stock 918 33 1,821 ----------- ----------- ----------- Balance at end of year (1,410) (2,328) (2,361) ----------- ----------- ----------- Treasury Stock Balance at beginning of year (98,735) (99,976) (101,518) Exercise of stock options 1,140 704 110 Awarded restricted stock, net of forfeitures (349) -- 1,136 Sale of stock under employee stock purchase plan 441 537 296 ----------- ----------- ----------- Balance at end of year - 3,729,769 shares of Common Stock in 2000, 3,777,319 shares in 1999 and 3,824,838 shares in 1998 (97,503) (98,735) (99,976) ----------- ----------- ----------- Total Stockholders' Equity $ 1,259,560 1,057,172 978,233 =========== =========== =========== </TABLE> 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 oil operation, operates two petroleum refineries in the United States and has an interest in a U.K. refinery. Murphy markets petroleum products under various brand names and to unbranded wholesale customers in the United States and the United Kingdom. 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. REVENUE RECOGNITION - Revenues associated with sales of refined products and the Company's share of crude oil production are recorded when title passes to the customer. The Company uses the sales method to record revenues associated with natural gas production. The Company records a liability for natural gas balancing when the Company has sold more than its working interest share of natural gas production and the estimated remaining reserves make it doubtful that partners can recoup their share of production from the field. At December 31, 2000 and 1999, the liabilities for gas balancing arrangements were immaterial. Excise taxes collected on sales of refined products and remitted to governmental agencies are not included in revenues or in costs and expenses. 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. 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 properties are evaluated on a specific asset basis or in groups of similar assets, as applicable. An impairment is recognized when the estimated undiscounted future net cash flows of an evaluated asset are less than its carrying value. Depreciation and depletion of producing oil and gas properties are recorded 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. Refineries and certain marketing facilities are depreciated primarily using the composite straight-line method. Gasoline stations and 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) INVENTORIES - Inventories of crude oil other than refinery feedstocks are valued at the lower of cost, generally applied on a first-in-first-out (FIFO) basis, or market. Inventories of refinery feedstocks and finished 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. GOODWILL - The excess of the purchase price over the fair value of net assets acquired associated with the purchase of Beau Canada Exploration Ltd. (Beau Canada) was recorded as goodwill and is being amortized on a straight-line basis over 15 years. The Company assesses the recoverability of goodwill by comparing undiscounted future net cash flows for western Canadian oil and gas properties with the unamortized goodwill balance. 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. Petroleum revenue taxes are provided using the estimated effective tax rate over the life of applicable U.K. properties. The Company uses the deferral method to account for Canadian investment tax credits associated with the Hibernia and Terra Nova oil fields. 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 Loss 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, commodity prices and foreign currency exchange rates. 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. Effective January 1, 2001, the Company will adopt SFAS No. 133, which requires recognition of the fair value of all derivative instruments as assets or liabilities in its Consolidated Balance Sheet. The adoption of this standard will not have a significant effect on net income. Designated instruments that are highly effective at reducing the exposure of assets, liabilities or anticipated transactions to interest rate, commodity price or currency risks are accounted for as hedges. Gains and losses on an instrument accounted for as a hedge of anticipated transactions are generally deferred and recognized during the same period for which the underlying hedged exposures are recognized. Certain commodity instruments acquired through an acquisition have been recorded as a liability based on their fair value at date of acquisition; gains and losses on these instruments partially offset changes to the recorded liability. Gains or losses on derivatives that cease to qualify as hedges are recognized in income or expense. When derivative instruments accounted for as hedges are terminated prior to maturity, the resulting gain or loss is generally deferred and recognized at the time that the underlying hedged exposure is recognized. Gains and losses on interest rate swaps are recorded as an adjustment to Interest Expense in the Company's Consolidated Statements of Income. Gains and losses on crude oil and natural gas swaps that hedge the purchase prices of these commodities by the Company's refineries are recorded as a component of Crude Oil, Products and Related Operating Expenses in the Consolidated Statements of Income. Gains and losses on natural gas swaps that hedge the F-7
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) sales prices for certain natural gas produced and sold by the Company in Canada are recorded as an adjustment to the recorded liability in the Consolidated Balance Sheets or as an adjustment to Crude Oil and Natural Gas Sales in the Consolidated Statements of Income. 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 U.S. 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. Note B - New Accounting Principles In 2000, Murphy adopted the revenue recognition guidance in the Securities and Exchange Commission's Staff Accounting Bulletin 101. As a result of the change, Murphy records revenues related to its crude oil as the oil is sold, and carries its unsold crude oil production at cost rather than market value as in the past. Consequently, Murphy restated its operating results for the first three quarters of 2000 and recorded a transition adjustment of $8,733,000, net of income tax benefits of $3,886,000, for the cumulative effect on prior years. Excluding the cumulative effect transition adjustment, this accounting change increased income in 2000 by $1,145,000. The transition adjustment included a cumulative reduction of prior years' revenue of $20,591,000. Pro forma net income for the three years ended December 31, 2000, assuming that the new revenue recognition method had been applied retroactively in each year, was as follows: <TABLE> <CAPTION> (Thousands of dollars except per share data) 2000 1999 1998 ---- ---- ---- <S> <C> <C> <C> Net income (loss) - As reported $ 296,828 119,707 (14,394) Pro forma 305,561 111,336 (13,884) Net income (loss) per share - As reported, basic $ 6.59 2.66 (.32) Pro forma, basic 6.78 2.48 (.31) As reported, diluted 6.56 2.66 (.32) Pro forma, diluted 6.75 2.47 (.31) </TABLE> In 2000, the Company also applied the provisions of Emerging Issue Task Force (EITF) Issues 99-19, "Reporting Revenue Gross as a Principal Versus Net as an Agent," and 00-10, "Accounting for Shipping and Handling Fees." Prior to applying EITF 99-19, the Company reported the results of crude oil trading and certain other downstream activities on a net margin basis in either Other Operating Revenues or Crude Oil, Products and Related Operating Expenses in its Statements of Income and in its refining, marketing and transportation segment disclosures. Under EITF 99-19, the Company began reporting these activities as gross revenues and cost of sales. Before applying EITF 00-10, the Company reduced Crude Oil and Natural Gas Sales for certain gathering and pipeline charges incurred prior to the point of sale. Such costs have now been recorded as cost of sales rather than as a reduction of revenues. Due to applying these two accounting principles, the Company's previously reported revenues and cost of sales for the first nine months of 2000 and all preceding years presented have been reclassified to reflect the new presentation. Note C - Acquisition of Beau Canada Exploration Ltd. In early November 2000, Murphy acquired Beau Canada, an independent oil and natural gas company that primarily owned exploration licenses and producing natural gas and heavy oil fields in western Canada. The acquisition has been accounted for as a purchase; consequently, Beau Canada's operations subsequent to the acquisition date have been included in the Company's consolidated financial statements for the year ended December 31, 2000. The Company paid net cash of $127,476,000 to purchase all of Beau Canada's common stock at a price of approximately $1.44 a share. F-8
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The Company also assumed debt in the acquisition of $124,227,000 that was repaid before the end of the year through issuance of a structural loan (see Note F). Murphy recorded goodwill of $48,396,000 associated with the Beau Canada acquisition, primarily due to the purchase price being greater than the fair value of the net assets acquired and deferred income tax liabilities required to be established in recording the acquisition. The following table reflects the unaudited results of operations on a pro forma basis as if the Beau Canada acquisition had been completed at the beginning of 2000 and 1999. The pro forma financial information is not necessarily indicative of the operating results that would have occurred had the acquisition been consummated as of the dates indicated, nor is it necessarily indicative of future operating results. <TABLE> <CAPTION> Years Ended December 31, ------------------------ (Thousands of dollars except per share data) 2000 1999 ---- ---- <S> <C> <C> Pro forma revenues $ 4,727,574 2,830,973 Pro forma income from continuing operations 303,479 121,011 Pro forma income from continuing operations per Common share - diluted 6.71 2.69 </TABLE> Note D - Property, Plant and Equipment <TABLE> <CAPTION> December 31, 2000 December 31, 1999 ----------------------- ------------------------ (Thousands of dollars) Cost Net Cost Net ---------- ---------- ----------- ---------- <S> <C> <C> <C> <C> Exploration and production $4,156,422 1,616,424* 3,750,077 1,324,685* Refining 710,623 256,469 698,100 259,883 Marketing 307,429 224,677 219,124 140,786 Transportation 111,409 62,210 84,391 38,762 Corporate and other 43,205 24,939 38,627 18,625 ---------- ---------- ---------- ---------- $5,329,088 2,184,719 4,790,319 1,782,741 ========== ========== ========== ========== </TABLE> *Includes $17,370 in 2000 and $16,270 in 1999 related to administrative assets and support equipment. In the 2000 and 1998 Consolidated Statements of Income, the Company recorded noncash charges of $27,916,000 and $80,127,000, respectively, for impairment of certain properties. After related income tax benefits, these write-downs reduced net income by $17,817,000 in 2000 and $57,573,000 in 1998. The 2000 charges related to two natural gas fields in the Gulf of Mexico and two Canadian heavy oil properties that depleted earlier than anticipated. 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 carrying values for properties determined to be impaired were reduced to the assets' fair values based on projected future discounted net cash flows, using the Company's estimates of future commodity prices. Note E - Financing Arrangements At December 31, 2000, the Company had an unused 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. U.S. dollar and Canadian dollar commercial paper totaling an equivalent US $110,633,000 at December 31, 2000 was outstanding and classified as nonrecourse debt. This outstanding debt is supported by a similar amount of credit facilities with major banks based on 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 during 2002. In addition, the Company had unused uncommitted lines of credit with banks at December 31, 2000 totaling an equivalent US $155,548,000 for a combination of U.S. dollar and Canadian dollar borrowings. F-9
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The Company has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of up to $1 billion in debt and equity securities. No securities had been issued under this shelf registration as of December 31, 2000. Note F - Long-term Debt <TABLE> <CAPTION> December 31 (Thousands of dollars) 2000 1999 --------- --------- <S> <C> <C> Notes payable 7.05% notes, due 2029 $ 247,369 247,277 6.23% structured loan, due 2001-2005 175,000 -- Other, 6% to 8%, due 2001-2021 1,244 1,363 --------- --------- Total notes payable 423,613 248,640 --------- --------- Nonrecourse debt of a subsidiary Guaranteed credit facilities with banks Commercial paper, 5.73% to 6.60%, $41,233 payable in Canadian dollars, supported by credit facility, due 2001-2008 110,633 112,191 Loan payable to Canadian government, interest free, payable in Canadian dollars, due 2001-2008 27,755 32,404 --------- --------- Total nonrecourse debt of a subsidiary 138,388 144,595 --------- --------- Total debt including current maturities 562,001 393,235 Current maturities (37,242) (71) --------- --------- Total long-term debt $ 524,759 393,164 ========= ========= </TABLE> Maturities for the four years after 2001 are: $45,412,000 in 2002, $48,805,000 in 2003, $51,985,000 in 2004 and $63,062,000 in 2005. In 1999, $250,000,000 of 7.05% notes were issued in the public market. These notes mature in May 2029 and are shown in the above table net of unamortized discount. With the support of a major bank consortium, the structured loan was borrowed by a Canadian subsidiary in December 2000 to replace temporary financing of the Beau Canada acquisition. The 6.23% fixed-rate loan reduces in quarterly installments over a five-year period beginning in 2001. Payment of interest under the loan has been guaranteed by the Company. 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. Additionally, payment is secured by a debenture that mortgages the Company's share of the Hibernia properties and the production therefrom. Recourse of the lenders is limited to the Canadian government's guarantee; the government's recourse to the Company is limited, subject to certain covenants, to Murphy's interest in the assets and operations of Hibernia. The Company has borrowed the maximum amount available under the Primary Guarantee Facility at December 31, 2000. Beginning in 2001, the amount guaranteed will reduce quarterly by the greater of 30% of Murphy's after-tax free cash flow from Hibernia or 1/32 of the original total guarantee. 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. The outstanding balance is to be repaid in equal annual installments through 2008. Note G - Provision for Reduction in Force In early 1999, the Company offered enhanced voluntary retirement benefits to eligible exploration, production and administrative employees in its New Orleans and Calgary offices and severed certain other employees at these F-10
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) locations. The voluntary retirements and severances reduced the Company's workforce by 31 employees, and a charge of $1,513,000 was recorded to income in 1999. The provision included additional defined benefit plan expense of $1,041,000 and severance and other costs of $472,000, the latter of which was essentially all paid during 1999. Note H - Income Taxes The components of income (loss) before income taxes and cumulative effect of accounting change for each of the three years ended December 31, 2000 and income tax expense (benefit) attributable thereto were as follows. <TABLE> <CAPTION> (Thousands of dollars) 2000 1999 1998 --------- --------- --------- <S> <C> <C> <C> Income (loss) before income taxes and cumulative effect of accounting change United States $ 102,519 15,074 44,600 Foreign 362,815 163,428 (52,877) --------- --------- --------- $ 465,334 178,502 (8,277) ========= ========= ========= Income tax expense (benefit) before cumulative effect of accounting change Federal - Current/1/ $ 19,215 (13,497) 6,431 Deferred 5,665 1,597 6,232 Noncurrent (2,261) 16,366 3,785 --------- --------- --------- 22,619 4,466 16,448 --------- --------- --------- State - Current 3,129 1,342 2,021 --------- --------- --------- Foreign - Current 76,184 40,726 (3,498) Deferred/2/ 59,776 11,165 (10,201) Noncurrent (1,935) 1,096 1,347 --------- --------- --------- 134,025 52,987 (12,352) --------- --------- --------- Total $ 159,773 58,795 6,117 ========= ========= ========= </TABLE> /1/ Net of benefit of $3,150 in 2000 for alternative minimum tax credits. /2/ Net of benefit of $609 in 1999 for a reduction in the U.K. tax rate. Total income tax expense in 2000, including tax benefits associated with the cumulative effect of accounting change, was $155,887,000. 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 following table reconciles income taxes based on the U.S. statutory tax rate to the Company's income tax expense before cumulative effect of accounting change. <TABLE> <CAPTION> (Thousands of dollars) 2000 1999 1998 --------- --------- --------- <S> <C> <C> <C> Income tax expense (benefit) based on the U.S. statutory tax rate $ 162,867 62,475 (2,897) Foreign income subject to foreign taxes at a rate different than the U.S. statutory rate 13,010 1,988 5,692 State income taxes 2,034 872 1,313 Settlement of U.S. taxes (17,016) (5,000) (704) Settlement of foreign taxes -- -- (1,410) Foreign asset impairment with no tax benefit -- -- 5,293 Other, net (1,122) (1,540) (1,170) --------- --------- --------- Total $ 159,773 58,795 6,117 ========= ========= ========= </TABLE> F-11
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, 2000 and 1999 showing the tax effects of significant temporary differences follows. <TABLE> <CAPTION> (Thousands of dollars) 2000 1999 ---- ---- <S> <C> <C> Deferred tax assets Property and leasehold costs $ 70,570 64,469 Reserves for dismantlements and major repairs 63,754 53,470 Federal alternative minimum tax credit carryforward -- 3,177 Postretirement and other employee benefits 27,950 24,637 Foreign tax operating losses 27,888 23,135 Other deferred tax assets 26,681 29,379 --------- --------- Total gross deferred tax assets 216,843 198,267 Less valuation allowance (60,958) (57,388) --------- --------- Net deferred tax assets 155,885 140,879 --------- --------- Deferred tax liabilities Property, plant and equipment (45,860) (32,985) Accumulated depreciation, depletion and amortization (285,444) (213,674) Other deferred tax liabilities (28,633) (27,364) --------- --------- Total gross deferred tax liabilities (359,937) (274,023) --------- --------- Net deferred tax liabilities $(204,052) (133,144) ========= ========= </TABLE> The Company has tax loss and other carryforwards of $111,551,000 associated with its operations in Ecuador. The losses have a carryforward period of no more than five years, with certain losses limited to 25% of each year's taxable income. These losses begin to expire in 2002. 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 $3,570,000 in 2000, but decreased $4,970,000 in 1999; the change in each year primarily offset the change in certain deferred tax assets. Any subsequent reductions of the valuation allowance will be reported as reductions of tax expense assuming no offsetting change in the deferred tax asset. The Company has not recorded a deferred tax liability of $27,625,000 related to undistributed earnings of certain foreign subsidiaries at December 31, 2000 because the earnings are considered permanently invested. Tax returns are subject to audit by various taxing authorities. In 2000, 1999 and 1998, the Company recorded benefits to income of $25,618,000, $5,000,000 and $2,114,000, respectively, from settlements of U.S. and foreign tax issues primarily related to prior years. The Company believes that adequate accruals have been made for unsettled issues. Note I - 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 1% (.5% prior to 2000) 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 changes in fair market value of Common Stock. Compensation cost charged against (credited to) income for stock-based plans was $7,914,000 in 2000, $13,161,000 in 1999 and $(4,646,000) in 1998; outstanding awards were not significantly modified in the last three years. F-12
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Had compensation cost of the Plan been based on the fair value of the instruments at the date of grant using the provisions of Statement of Financial Accounting Standards (SFAS) No. 123, 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. <TABLE> <CAPTION> (Thousands of dollars except per share data) 2000 1999 1998 ---- ---- ---- <S> <C> <C> <C> Net income (loss) - As reported $ 296,828 119,707 (14,394) Pro forma 299,031 124,543 (18,182) Earnings per share - As reported, basic $ 6.59 2.66 (.32) Pro forma, basic 6.64 2.77 (.40) As reported, diluted 6.56 2.66 (.32) Pro forma, diluted 6.61 2.76 (.40) </TABLE> 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. Generally, one-half of each grant may be exercised after two years and the remainder after three years. The pro forma net income calculations in the preceding table reflect the following fair values of options granted in 2000, 1999 and 1998; fair values of options have been estimated by using the Black-Scholes pricing model and the assumptions as shown. <TABLE> <CAPTION> 2000 1999 1998 ---- ---- ---- <S> <C> <C> <C> Fair value per share at grant date $ 15.00 $ 7.76 $ 9.01 Assumptions Dividend yield 2.91% 2.87% 2.91% Expected volatility 26.06% 24.21% 17.27% Risk-free interest rate 6.76% 4.77% 5.46% Expected life 5 yrs. 5 yrs. 5 yrs. </TABLE> Changes in options outstanding, including shares issued under a prior plan, were as follows. <TABLE> <CAPTION> Average Number Exercise of Shares Price --------- ----- <S> <C> <C> 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 Granted at FMV 325,500 35.69 Exercised (109,130) 39.57 Forfeited (15,250) 45.27 --------- Outstanding at December 31, 1999 1,254,369 46.19 Granted at FMV 396,000 56.97 Exercised (192,549) 43.63 Forfeited (5,250) 49.75 --------- Outstanding at December 31, 2000 1,452,570 49.45 ========= Exercisable at December 31, 1998 284,529 $ 39.53 Exercisable at December 31, 1999 441,119 45.36 Exercisable at December 31, 2000 590,820 51.80 </TABLE> F-13
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Additional information about stock options outstanding at December 31, 2000 is shown below. <TABLE> <CAPTION> Options Outstanding Options Exercisable ------------------------------------------ ------------------------ Range of Exercise No. of Avg. Life Avg. No. of Avg. Prices Per Share Options in Years Price Options Price - ---------------- ------- -------- ----- ------- ----- <S> <C> <C> <C> <C> <C> $34.56 to $42.25 443,570 6.9 $ 36.88 123,070 $ 39.99 $49.75 to $50.38 396,250 6.8 49.94 251,000 50.06 $55.41 to $65.49 612,750 8.0 58.23 216,750 60.54 --------- ------- 1,452,570 7.4 49.45 590,820 51.80 ========= ======= </TABLE> 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 - Shares of restricted stock were granted under the Plan in certain 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 receives dividends and may vote these 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 value per share of restricted stock granted in 1998 was $49.50, the market price of the stock at the date granted. On December 31, 2000, approximately 50% of eligible shares granted in 1996 were awarded, and the remaining shares were forfeited based on financial objectives achieved. On December 31, 1998, all shares granted in 1994 were forfeited because financial objectives were not achieved. Changes in restricted stock outstanding were as follows. <TABLE> <CAPTION> (Number of shares) 2000 1999 1998 ---- ---- ---- <S> <C> <C> <C> Balance at beginning of year 83,364 83,364 39,856 Granted -- -- 59,750 Awarded (12,077) -- -- Forfeited (12,954) -- (16,242) ------- ------- ------- Balance at end of year 58,333 83,364 83,364 ======= ======= ======= </TABLE> 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 $6,970,000, $5,301,000 and $518,000 was recorded in 2000, 1999, and 1998, respectively, for these plans. EMPLOYEE STOCK PURCHASE PLAN (ESPP) - The Company has an ESPP, under which, as amended in 2000, 150,000 shares of the Company's Common Stock could be purchased by employees. Each quarter, an eligible U.S. or Canadian 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 150,000 shares or June 30, 2007. Employee stock purchases under the ESPP were 13,675 shares at an average price of $51.08 a share in 2000, 20,487 shares at $37.56 in 1999 and 11,315 shares at $48.81 in 1998. At December 31, 2000, 100,197 shares remained available for sale under the ESPP. Compensation costs related to the ESPP were immaterial. F-14
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Note J - Employee and Retiree Benefit Plans PENSION AND POSTRETIREMENT PLANS - The Company has noncontributory defined benefit pension plans that cover substantially all full-time employees. During 2000, certain employees in Canada converted their defined benefit pension plan coverage to a contributory defined contribution plan. Henceforth, new Canadian employees may only participate in the defined contribution plan. The Company recorded a settlement gain of $1,824,000 associated with these conversions in 2000. The Company also sponsors health care and life insurance benefit plans 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, 2000 and 1999 and a statement of the funded status as of December 31, 2000 and 1999. <TABLE> <CAPTION> Pension Postretirement Benefits Benefits ---------------------- -------------------- (Thousands of dollars) 2000 1999 2000 1999 ---- ---- ---- ---- <S> <C> <C> <C> <C> Change in benefit obligation Obligation at January 1 $ 240,630 238,022 34,350 36,749 Service cost 5,460 5,791 753 712 Interest cost 17,010 15,516 2,699 2,366 Plan amendments 3,502 225 -- -- Participant contributions -- -- 566 531 Actuarial (gain) loss 1,203 (6,167) 3,219 (2,916) Curtailment -- 226 -- -- Settlements (2,257) (82) -- -- Special early retirement benefits -- 1,079 -- -- Exchange rate changes (3,461) 18 -- -- Benefits paid (14,369) (13,998) (3,133) (3,092) --------- --------- --------- --------- Obligation at December 31 247,718 240,630 38,454 34,350 --------- --------- --------- --------- Change in plan assets Fair value of plan assets at January 1 304,474 286,846 -- -- Actual return on plan assets 15,393 30,613 -- -- Employer contributions 687 842 2,567 2,561 Participant contributions -- -- 566 531 Settlements (2,271) (82) -- -- Exchange rate changes (3,711) 253 -- -- Benefits paid (14,369) (13,998) (3,133) (3,092) --------- --------- --------- --------- Fair value of plan assets at December 31 300,203 304,474 -- -- --------- --------- --------- --------- Reconciliation of funded status Funded status at December 31 52,485 63,844 (38,454) (34,350) Unrecognized actuarial (gain) loss (22,440) (43,292) 6,594 3,610 Unrecognized transition asset (13,047) (8,729) -- -- Unrecognized prior service cost 7,806 6,391 -- -- --------- --------- --------- --------- Net plan asset (liability) recognized $ 24,804 18,214 (31,860) (30,740) ========= ========= ========= ========= Amounts recognized in the Consolidated Balance Sheets at December 31 Prepaid benefit asset $ 40,152 34,200 -- -- Accrued benefit liability (17,051) (16,300) (31,860) (30,740) Intangible asset 1,703 314 -- -- --------- --------- --------- --------- Net plan asset (liability) recognized $ 24,804 18,214 (31,860) (30,740) ========= ========= ========= ========= </TABLE> F-15
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The Company's U.S. and Canadian nonqualified retirement plans and U.S. directors' retirement plan were the only pension plans with accumulated benefit obligations in excess of plan assets at December 31, 2000 and 1999. The accumulated benefit obligations of these plans at December 31, 2000 and 1999 were $10,060,000 and $7,784,000, respectively; there were no assets in these plans. The Company's postretirement benefit plan had no plan assets; the benefit obligations for this plan at December 31, 2000 and 1999 were $38,454,000 and $34,350,000, respectively. The table that follows provides the components of net periodic benefit expense (credit) for each of the three years ended December 31, 2000. <TABLE> <CAPTION> Pension Benefits Postretirement Benefits -------------------------------- ------------------------------ (Thousands of dollars) 2000 1999 1998 2000 1999 1998 ---- ---- ---- ---- ---- ---- <S> <C> <C> <C> <C> <C> <C> Service cost $ 5,461 5,791 5,242 753 712 601 Interest cost 17,010 15,516 15,309 2,699 2,366 2,474 Expected return on plan assets (24,412) (23,105) (22,180) -- -- -- Amortization of prior service cost 791 622 626 -- -- -- Amortization of transitional asset (2,585) (2,204) (2,211) -- -- -- Recognized actuarial (gain) loss (395) (766) (758) 234 203 194 -------- -------- -------- -------- -------- -------- (4,130) (4,146) (3,972) 3,686 3,281 3,269 Settlement gain (1,824) -- -- -- -- -- Special early retirement benefits -- 1,041 -- -- -- -- -------- -------- -------- -------- -------- -------- Net periodic benefit expense (credit) $ (5,954) (3,105) (3,972) 3,686 3,281 3,269 ======== ======== ======== ======== ======== ======== </TABLE> The preceding tables include the following amounts related to foreign benefit plans. <TABLE> <CAPTION> Pension Postretirement Benefits Benefits ------------------- ------------------- (Thousands of dollars) 2000 1999 2000 1999 ---- ---- ---- ---- <S> <C> <C> <C> <C> Benefit obligation at December 31 $ 49,608 53,675 - - Fair value of plan assets at December 31 55,473 61,462 - - Net plan liability recognized (876) (3,178) - - Net periodic benefit expense (credit) (1,960) 364 - - </TABLE> The following table provides the weighted-average assumptions used in the measurement of the Company's benefit obligations at December 31, 2000 and 1999. <TABLE> <CAPTION> Pension Postretirement Benefits Benefits ------------------- ------------------- 2000 1999 2000 1999 ---- ---- ---- ---- <S> <C> <C> <C> <C> Discount rate 7.25% 7.26% 7.50% 7.50% Expected return on plan assets 8.33% 8.34% - - Rate of compensation increase 4.63% 4.66% - - </TABLE> For purposes of measuring postretirement benefit obligations at December 31, 2000, the future annual rates of increase in the cost of health care were assumed to be 5.5% for 2001 and 4.5% for 2002 and beyond. F-16
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 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. <TABLE> <CAPTION> (Thousands of dollars) 1% Increase 1% Decrease ----------- ----------- <S> <C> <C> Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 2000 $ 236 (224) Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2000 2,191 (2,123) </TABLE> THRIFT PLANS - Most employees of the Company may participate in thrift or savings 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. Amounts charged to expense for these plans were $3,699,000 in 2000, $2,523,000 in 1999 and $3,333,000 in 1998. Note K - 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, 2000 and 1999, 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 an average interest rate of 6.46% over their composite lives and to receive a variable rate, which averaged 6.72% at December 31, 2000. The variable rate received by the Company under each contact is repriced quarterly. Prior to April 2000, the Company was a party to crude oil swap agreements for a total notional volume of 2.3 million barrels that reduced a portion of the financial exposure of Murphy's U.S. refineries to crude oil price movements in 2001 and 2002. Under each swap agreement, Murphy would have paid a fixed crude oil price and would have received the average near-month NYMEX West Texas Intermediate crude oil price during the agreement's contractual maturity period. In April 2000, Murphy settled contracts for 1.7 million barrels, receiving cash of $5,806,000 from the counterparties, and entered into offsetting contracts for the remaining swap agreements, locking in a future cash settlement of $1,929,000. These settlement gains have been deferred and will be recognized as a reduction of costs of crude oil purchases in 2001 and 2002. The Company periodically uses natural gas swap agreements to reduce a portion of the financial exposure of its Meraux, Louisiana refinery to fluctuations in the price of natural gas purchased for fuel. At December 31, 2000, Murphy was a party to natural gas swap agreements for a total notional volume of 7 million MMBTU that hedge natural gas purchases in 2002 through 2004. The swaps require Murphy to pay an average natural gas price of $2.61 an MMBTU and to receive the average NYMEX Henry Hub price for the final three trading days of each respective month. Unrealized gains or losses on such swap contracts are deferred and recognized in connection with the associated fuel purchases. The Company has natural gas swaps obtained through the acquisition of Beau Canada that reduce a portion of the financial exposure of certain Canadian natural gas production to fluctuations in sales prices. At December 31, 2000, Murphy was a party to natural gas swap agreements for the sale of a notional amount of 20,000 gigajoules (GJ) per day through October 2001. The swaps require Murphy to pay based on the AECO "C" index and to receive an average of C$2.47 per GJ. In addition, the Company was a party to a natural gas swap agreement for the purchase of 10,000 GJ per day through October 2001. The swap requires Murphy to pay C$5.64 per GJ and to receive based on the AECO "C" index. The fair value of these swaps was recorded as a net liability upon the acquisition of Beau Canada. The swaps are settled monthly and net payments by the Company are recorded as a reduction of the associated liability, with any differences recorded as an adjustment of natural gas sales revenue. F-17
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) FAIR VALUE - The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 2000 and 1999. 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. <TABLE> <CAPTION> 2000 1999 ------------------------ ------------------------ Carrying Fair Carrying Fair (Thousands of dollars) Amount Value Amount Value ------ ----- ------ ----- <S> <C> <C> <C> <C> Financial liabilities and deferred credits Current and long-term debt $ (562,001) (526,891) (393,235) (373,546) Natural gas swaps (12,615) (17,905) - - Off-balance-sheet exposures - unrealized gain (loss) Interest rate swaps - (1,956) - 266 Crude oil swaps - 1,793 - 2,668 Natural gas swaps - 6,196 - (83) Financial guarantees and letters of credit - - - - </TABLE> The carrying amounts of current and long-term debt 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 recorded natural gas swaps are included in Other Accrued Liabilities. 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, crude oil swaps and natural gas swaps - The fair values are based on published index prices or quotes from counterparties. . Financial guarantees and letters of credit - The fair value, which represents fees associated with obtaining the instruments, was nominal. 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, which 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. F-18
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Note L - 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, as amended, between the Company and Harris Trust Company of New York, as Rights Agent. Note M - Earnings per Share The following table reconciles the weighted-average shares outstanding for computation of basic and diluted income (loss) per Common share for each of the three years ended December 31, 2000. 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) 2000 1999 1998 ---------- ---------- ---------- Basic method 45,031,665 44,970,457 44,955,679 Dilutive stock options 208,041 59,768 -- ---------- ---------- ---------- Diluted method 45,239,706 45,030,225 44,955,679 ========== ========== ========== The computations of diluted earnings per share in the Consolidated Statements of Income did not consider outstanding options at year end of 147,000 shares in 2000, 684,750 shares in 1999 and 1,053,249 shares in 1998 because the effects of these options would have improved the Company's earnings per share. Average exercise prices per share of the options not used were $62.97, $53.34 and $48.73, respectively. Note N - Other Financial Information INVENTORIES - Inventories accounted for under the LIFO method totaled $85,968,000 and $72,452,000 at December 31, 2000 and 1999, respectively, and were $123,963,000 and $115,236,000 less than such inventories would have been valued using the first-in first-out method. FOREIGN CURRENCY - Cumulative translation gains and losses, net of insignificant related income tax effects, are included in Accumulated Other Comprehensive Loss in the Consolidated Balance Sheets. At December 31, 2000, components of the net cumulative loss of $38,266,000 were gains (losses) of $12,715,000 for pounds sterling, $(51,248,000) for Canadian dollars and $267,000 for other currencies. Comparability of net income was not significantly affected by exchange rate fluctuations in 2000, 1999 or 1998. Net gains (losses) from foreign currency transactions included in the Consolidated Statements of Income were $252,000 in 2000, $(847,000) in 1999 and $282,000 in 1998. F-19
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) CASH FLOW DISCLOSURES - In association with the Beau Canada acquisition, the Company assumed debt of $124,227,000, a nonmonetary transaction excluded from both financing and investing activities in the Consolidated Statement of Cash Flows for the year ended December 31, 2000. Cash income taxes paid (refunded) were $53,583,000, $(5,343,000) and $26,227,000 in 2000, 1999 and 1998, respectively. Interest paid, net of amounts capitalized, was $15,185,000, $17,140,000 and $9,551,000 in 2000, 1999 and 1998, respectively. Noncash operating working capital (increased) decreased for each of the three years ended December 31, 2000 as follows. <TABLE> <C> (Thousands of dollars) 2000 1999 1998 ---- ---- ---- <S> <C> <C> <C> Accounts receivable $ (95,675) (123,566) 38,541 Inventories (12,197) (21,866) 28,639 Prepaid expenses 5,794 4,147 15,031 Deferred income tax assets (4,196) (8,600) 2,158 Accounts payable and accrued liabilities 142,228 99,382 (85,503) Current income tax liabilities 30,048 15,344 (2,676) --------- --------- --------- Net (increase) decrease in noncash operating working capital excluding acquisition of Beau Canada $ 66,002 (35,159) (3,810) ========= ========= ========= </TABLE> Note O - Commitments The Company leases land, gasoline stations and other facilities under operating leases. Future minimum rental commitments under noncancellable operating leases are not material. Commitments for capital expenditures were approximately $353,000,000 at December 31, 2000, including $176,000,000 related to a clean fuels expansion project at the Meraux refinery and $67,000,000 related to the Company's multiyear contract for a semisubmersible deepwater drilling rig. Certain costs committed under the rig contract will be charged to the Company's partners when future deepwater wells are drilled. Note P - 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; 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; restrictions on drilling and/or production; 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. ENVIRONMENTAL MATTERS - On June 29, 2000, the U.S. Government and the State of Wisconsin each filed a lawsuit against Murphy in the U.S. District Court for the Western District of Wisconsin. The State action was subsequently dismissed by the federal court and refiled in state court in Douglas County, Wisconsin. The suits, arising out of a 1998 compliance inspection, include claims for alleged violations of federal and state environmental laws at Murphy's Superior, Wisconsin refinery. The suits seek compliance as well as substantial monetary penalties. The Company believes it has valid defenses to these allegations and plans a vigorous defense. The Company does not have an estimate or a range of potential liability at this time and can give no assurance about the outcome. The Company does not believe that the resolution of these suits or other known environmental matters will have a material adverse effect on its financial condition. There is the possibility that expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. Such expenditures could materially affect the results of operations in a future period. F-20
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Other matters related to the Company's environmental contingencies are reviewed in Management's Discussion and Analysis of Financial Condition and Results of Operations under the section entitled "Environmental" beginning on page 15 of this Form 10-K report. OTHER MATTERS - The Company and its subsidiaries are engaged in a number of other 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 financial guarantees or letters of credit that may be drawn upon if the Company fails to perform under those contracts. At December 31, 2000, the Company had contingent liabilities of $128,500,000 under certain financial guarantees and $58,200,000 on outstanding letters of credit. Note Q - Subsequent Event (unaudited) On March 1, 2001, the Company announced it had entered into an agreement, subject to conditions, to sell its Canadian pipeline and trucking operation for total proceeds of approximately $163,000,000, including inventory. The transaction should close in the second quarter and would result in an after-tax gain of approximately $69,000,000. Note R - 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 operations, excluding interest income and interest expense. Intersegment transfers of crude oil, natural gas 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 $1,052,760,000, $898,917,000 and $831,385,000 for the years 2000, 1999 and 1998, 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 and losses, interest expense and unallocated overhead, are shown in the tables to reconcile the business segments to consolidated totals. As used in the table on page F-22, Certain Long-Lived Assets at December 31 exclude investments, noncurrent receivables, deferred tax assets and intangible assets. In the tables on pages F-22 and F-23, certain amounts for 1999 and 1998 have been reclassified to conform to 2000 presentation. F-21
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) <TABLE> <CAPTION> Exploration and Production Segment Information ------------------------------------------------------------------- (Millions of dollars) U.S. Canada U.K. Ecuador Other Total --- ------ --- ------- ----- ----- <S> <C> <C> <C> <C> <C> <C> Year ended December 31, 2000 Segment income (loss) before cumulative effect of accounting change $ 50.3 108.1 90.2 21.1 (17.0) 252.7 Revenues from external customers 205.6 278.6 211.5 51.5 2.2 749.4 Intersegment revenues 73.4 106.3 11.6 - - 191.3 Interest income - - - - - - Interest expense, net of capitalization - - - - - - Income of equity companies - - - - - - Income tax expense (benefit) 27.1 66.3 56.2 - - 149.6 Significant noncash charges (credits) Depreciation, depletion, amortization 50.2 70.0 41.7 6.8 .5 169.2 Impairment of properties 21.0 6.9 - - - 27.9 Provisions for major repairs - 3.3 - - - 3.3 Amortization of undeveloped leases 7.7 6.4 - - - 14.1 Deferred and noncurrent income taxes (5.1) 55.6 (1.5) - 1.0 50.0 Additions to property, plant, equipment 69.9 425.5 24.6 12.3 8.9 541.2 Total assets at year-end 413.6 1,131.1 261.7 79.8 16.4 1,902.6 - ------------------------------------------------------------------------------------------------------------------------------------ Year ended December 31, 1999 Segment income (loss) $ 35.3 47.0 37.2 22.6 (7.7) 134.4 Revenues from external customers 155.8 164.2 119.0 39.0 2.0 480.0 Intersegment revenues 50.6 58.7 23.4 - - 132.7 Interest income - - - - - - Interest expense, net of capitalization - - - - - - Income of equity companies - - - - - - Income tax expense (benefit) 10.3 24.8 24.5 - .5 60.1 Significant noncash charges (credits) Depreciation, depletion, amortization 65.1 50.9 42.8 8.0 .1 166.9 Provisions for major repairs - 2.5 - - - 2.5 Amortization of undeveloped leases 7.0 4.0 - - - 11.0 Deferred and noncurrent income taxes 12.6 21.3 (3.8) - 1.3 31.4 Additions to property, plant, equipment 60.7 143.0 25.6 7.1 (.1) 236.3 Total assets at year-end 391.0 737.9 299.4 60.0 9.5 1,497.8 - ------------------------------------------------------------------------------------------------------------------------------------ Year ended December 31, 1998 Segment income (loss) $ .7 (7.5) (13.3) 4.8 (35.1) (50.4) Revenues from external customers 151.2 95.6 82.8 26.4 2.7 358.7 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 44.5 42.9 10.2 - 163.6 Impairment of properties 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 - ------------------------------------------------------------------------------------------------------------------------------------ <CAPTION> Geographic Information Certain Long-Lived Assets at December 31 ------------------------------------------------------------------ (Millions of dollars) U.S. Canada U.K. Ecuador Other Total ---- ------ ---- ------- ----- ----- <S> <C> <C> <C> <C> <C> <C> 2000 $ 764.8 1,063.2 297.1 59.0 14.6 2,198.7 1999 687.0 724.4 331.6 53.5 7.7 1,804.2 1998 675.5 600.4 352.0 54.3 8.4 1,690.6 </TABLE> F-22
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) <TABLE> <CAPTION> Segment Information (Continued) Refining, Marketing & Transportation ------------------------------------ Corp. & Consoli- (Millions of dollars) U.S. U.K. Canada Total Other dated ---- ---- ------ ----- ----- ----- <S> <C> <C> <C> <C> <C> <C> Year ended December 31, 2000 Segment income (loss) before cumulative effect of accounting change $ 23.9 23.0 7.6 54.5 (1.7) 305.5 Revenues from external customers 2,842.1 458.2 564.6 3,864.9 24.9 4,639.2 Intersegment revenues .9 - .7 1.6 - 192.9 Interest income - - - - 21.7 21.7 Interest expense, net of capitalization - - - - 16.3 16.3 Income of equity companies .6 - - .6 - .6 Income tax expense (benefit) 13.2 11.3 6.9 31.4 (21.2) 159.8 Significant noncash charges (credits) Depreciation, depletion, amortization 32.7 5.6 2.6 40.9 3.4 213.5 Impairment of properties - - - - - 27.9 Provisions for major repairs 17.6 1.8 - 19.4 .1 22.8 Amortization of undeveloped leases - - - - - 14.1 Deferred and noncurrent income taxes 5.2 1.2 - 6.4 7.0 63.4 Additions to property, plant, equipment 112.0 12.4 29.4 153.8 11.4 706.4 Total assets at year-end 670.4 222.6 125.6 1,018.6 213.2 3,134.4 - --------------------------------------------------------------------------------------------------------------------------- Year ended December 31, 1999 Segment income (loss) $ 1.6 14.0 6.8 22.4 (37.1) 119.7 Revenues from external customers 1,641.4 337.9 292.7 2,272.0 4.4 2,756.4 Intersegment revenues 4.6 - .6 5.2 - 137.9 Interest income - - - - 3.9 3.9 Interest expense, net of capitalization - - - - 20.3 20.3 Income of equity companies .5 - - .5 - .5 Income tax expense (benefit) .4 6.6 6.6 13.6 (14.9) 58.8 Significant noncash charges (credits) Depreciation, depletion, amortization 27.6 5.8 2.0 35.4 2.7 205.0 Provisions for major repairs 14.2 1.9 - 16.1 .1 18.7 Amortization of undeveloped leases - - - - - 11.0 Deferred and noncurrent income taxes 7.9 (.5) - 7.4 (.8) 38.0 Additions to property, plant, equipment 76.4 11.4 .3 88.1 2.6 327.0 Total assets at year-end 549.7 199.0 89.6 838.3 109.4 2,445.5 - --------------------------------------------------------------------------------------------------------------------------- Year ended December 31, 1998 Segment income (loss) $ 27.7 17.3 2.5 47.5 (11.5) (14.4) Revenues from external customers 1,413.9 287.9 282.1 1,983.9 4.4 2,347.0 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 3.2 203.2 Impairment of properties - - .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 - --------------------------------------------------------------------------------------------------------------------------- </TABLE> <TABLE> Geographic Information Revenues from External Customers for the Year --------------------------------------------------------------------- (Millions of dollars) U.S. U.K. Canada Ecuador Other Total ---- ---- ------ ------- ----- ----- <S> <C> <C> <C> <C> <C> <C> 2000 $ 3,065.9 674.2 845.4 51.5 2.2 4,639.2 1999 1,798.4 459.8 457.2 39.0 2.0 2,756.4 1998 1,565.4 374.2 378.3 26.4 2.7 2,347.0 </TABLE> F-23
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. 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 year-end 2000 crude oil prices used for this calculation were $23.24 a barrel for the United States, $24.73 for Canadian light, $7.74 for Canadian heavy, $22.97 for Canadian offshore, $22.33 for the United Kingdom and $17.75 for Ecuador. Average year-end 2000 natural gas prices used were $6.58 an MCF for the United States, $5.68 for Canada and $2.76 for the United Kingdom. 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, 2000. F-24
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued) Schedule 1 - Estimated Net Proved Oil Reserves <TABLE> <CAPTION> Crude Oil, Condensate and Natural Gas Liquids ----------------------------------------------------- Synthetic United United Oil - (Millions of barrels) States Canada Kingdom Ecuador Total Canada Total ------ ------ ------- ------- ----- ------ ----- <S> <C> <C> <C> <C> <C> <C> <C> Proved 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 Revisions of previous estimates (1.6) 9.1 7.7 4.5 19.7 8.9 28.6 Extensions and discoveries 15.8 .7 - 2.9 19.4 - 19.4 Production (3.1) (6.9) (7.5) (2.6) (20.1) (4.0) (24.1) ---- ---- ---- ---- ----- ---- ----- December 31, 1999 34.1 53.7 56.9 37.0 181.7 120.5 302.2 Revisions of previous estimates (1.7) 4.5 1.8 3.6 8.2 7.6 15.8 Purchases - 11.7 - - 11.7 - 11.7 Extensions and discoveries 15.3 4.0 - 2.6 21.9 - 21.9 Production (2.4) (8.4) (7.7) (2.3) (20.8) (3.1) (23.9) Sales - (1.6) - - (1.6) - (1.6) ---- ---- ---- ---- ----- ---- ----- December 31, 2000 45.3 63.9 51.0 40.9 201.1 125.0 326.1 ==== ==== ==== ==== ===== ==== ===== Proved Developed 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 December 31, 1999 11.7 26.6 34.1 21.2 93.6 66.0 159.6 December 31, 2000 10.3 34.3 36.3 20.1 101.0 66.0 167.0 </TABLE> Schedule 2 - Estimated Net Proved Natural Gas Reserves <TABLE> <CAPTION> United United (Billions of cubic feet) States Canada Kingdom Total ------ ------ ------- ----- <S> <C> <C> <C> <C> Proved 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 Revisions of previous estimates (2.6) 5.5 3.9 6.8 Extensions and discoveries 53.6 10.8 - 64.4 Production (62.7) (20.6) (4.5) (87.8) Sales (1.1) - - (1.1) ------ ------ ----- ----- December 31, 1999 427.3 125.8 38.5 591.6 Revisions of previous estimates (41.9) (5.0) .3 (46.6) Purchases 5.4 163.3 - 168.7 Extensions and discoveries 31.2 40.1 - 71.3 Production (53.0) (27.0) (4.0) (84.0) Sales - (3.6) - (3.6) ------ ------ ----- ----- December 31, 2000 369.0 293.6 34.8 697.4 ====== ====== ===== ===== Proved Developed December 31, 1997 304.2 135.2 24.0 463.4 December 31, 1998 291.8 120.3 29.9 442.0 December 31, 1999 284.8 111.3 32.9 429.0 December 31, 2000 233.8 255.2 32.3 521.3 </TABLE> F-25
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 <TABLE> <CAPTION> Synthetic United United Oil - (Millions of dollars) States Canada Kingdom Ecuador Other Subtotal Canada Total ------ ------ ------- ------- ----- -------- ------ ----- <S> <C> <C> <C> <C> <C> <C> <C> <C> Year Ended December 31, 2000 Property acquisition costs Unproved $ 19.2 25.1 - - - 44.3 - 44.3 Proved 1.5 2.9 - - - 4.4 - 4.4 ------- ----- ---- ---- ---- ----- ---- ----- Total 20.7 28.0 - - - 48.7 - 48.7 Exploration costs 96.2 32.1 5.2 .1 23.1 156.7 - 156.7 Development costs 20.3 113.8 22.5 12.2 - 168.8 18.5 187.3 ------- ----- ---- ---- ---- ----- ---- ----- Total capital expenditures 137.2 173.9 27.7 12.3 23.1 374.2 18.5 392.7 ------- ----- ---- ---- ---- ----- ---- ----- Beau Canada property acquisition Unproved - 18.2 - - - 18.2 - 18.2 Proved - 241.8 - - - 241.8 - 241.8 ------- ----- ---- ---- ---- ----- ---- ----- Total - 260.0 - - - 260.0 - 260.0 ------- ----- ---- ---- ---- ----- ---- ----- Charged to expense Dry hole expense 56.7 5.7 1.7 - 1.9 66.0 - 66.0 Geophysical and other costs 10.6 21.2 1.4 - 12.3 45.5 - 45.5 ------- ----- ---- ---- ---- ----- ---- ----- Total charged to expense 67.3 26.9 3.1 - 14.2 111.5 - 111.5 ------- ----- ---- ---- ---- ----- ---- ----- Expenditures capitalized $ 69.9 407.0 24.6 12.3 8.9 522.7 18.5 541.2 ======= ===== ==== ==== ==== ===== ==== ===== Year Ended December 31, 1999 Property acquisition costs Unproved $ 12.1 6.2 - - - 18.3 - 18.3 Proved - .4 - - - .4 - .4 ------- ------- ----- ---- ---- ----- ---- ------ Total acquisition costs 12.1 6.6 - - - 18.7 - 18.7 Exploration costs 54.9 14.2 1.2 1.0 7.9 79.2 - 79.2 Development costs 28.6 108.2 28.3 6.1 - 171.2 26.8 198.0 ------- ----- ---- ---- ---- ----- ---- ----- Total capital expenditures 95.6 129.0 29.5 7.1 7.9 269.1 26.8 295.9 ------- ----- ---- ---- ---- ----- ---- ----- Charged to expense Dry hole expense 24.2 3.9 3.0 - 1.3 32.4 - 32.4 Geophysical and other costs 10.7 8.9 .9 - 6.7 27.2 - 27.2 ------- ----- ---- ---- ---- ----- ---- ----- Total charged to expense 34.9 12.8 3.9 - 8.0 59.6 - 59.6 ------- ----- ---- ---- ---- ----- ---- ----- Expenditures capitalized $ 60.7 116.2 25.6 7.1 (.1) 209.5 26.8 236.3 ======= ===== ==== ==== ==== ===== ==== ===== 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 ======= ===== ==== ==== ==== ===== ==== ===== </TABLE> F-26
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued) Schedule 4 - Results of Operations for Oil and Gas Producing Activities <TABLE> <CAPTION> Synthetic United United Oil - (Millions of dollars) States Canada Kingdom Ecuador Other Subtotal Canada Total ------ ------ ------- ------- ----- -------- ------ ----- <S> <C> <C> <C> <C> <C> <C> <C> <C> Year Ended December 31, 2000 Revenues Crude oil and natural gas liquids Transfers to consolidated operations $ 68.6 68.4 11.6 - - 148.6 37.9 186.5 Sales to unaffiliated enterprises 3.8 125.5 203.0 52.2 - 384.5 53.6 438.1 Natural gas Transfers to consolidated operations 4.8 - - - - 4.8 - 4.8 Sales to unaffiliated enterprises 206.6 99.0 7.8 - - 313.4 - 313.4 ------- ----- -------- ------- ------- ------- -------- ------ Total oil and gas revenues 283.8 292.9 222.4 52.2 - 851.3 91.5 942.8 Other operating revenues (4.8) .5 .7 (.7) 2.2 (2.1) - (2.1) ------- ----- -------- ------- ------- ------- -------- ------ Total revenues 279.0 293.4 223.1 51.5 2.2 849.2 91.5 940.7 ------- ----- -------- ------- ------- ------- -------- ------ Costs and expenses Production expenses 41.9 55.0 29.1 15.5 - 141.5 40.4 181.9 Exploration costs charged to expense 67.3 26.9 3.1 - 14.2 111.5 - 111.5 Undeveloped lease amortization 7.7 6.4 - - - 14.1 - 14.1 Depreciation, depletion and amortization 50.2 62.5 41.7 6.8 .5 161.7 7.5 169.2 Impairment of properties 21.0 6.9 - - - 27.9 - 27.9 Selling and general expenses 13.5 4.8 2.8 .3 4.5 25.9 .1 26.0 Loss on transportation and other disputed contractual items - - - 7.8 - 7.8 - 7.8 ------- ----- -------- ------- ------- ------- -------- ------ Total costs and expenses 201.6 162.5 76.7 30.4 19.2 490.4 48.0 538.4 ------- ----- -------- ------- ------- ------- -------- ------ 77.4 130.9 146.4 21.1 (17.0) 358.8 43.5 402.3 Income tax expense (benefit) 27.1 49.2 56.2 - - 132.5 17.1 149.6 ------- ----- -------- ------- ------- ------- -------- ------ Results of operations/1/ $ 50.3 81.7 90.2 21.1 (17.0) 226.3 26.4 252.7 ======= ===== ======== ======= ======= ======= ======== ====== Year Ended December 31, 1999 Revenues Crude oil and natural gas liquids Transfers to consolidated operations $ 48.8 15.9 23.4 - - 88.1 42.8 130.9 Sales to unaffiliated enterprises 5.6 91.8 111.3 36.1 - 244.8 32.0 276.8 Natural gas Transfer to consolidated operations 1.8 - - - - 1.8 - 1.8 Sales to unaffiliated enterprises 145.8 40.2 7.7 - - 193.7 - 193.7 ------- ----- ------- ------- ------- ------- -------- ------ Total oil and gas revenues 202.0 147.9 142.4 36.1 - 528.4 74.8 603.2 Other operating revenues/2/ 4.4 .2 - 2.9 2.0 9.5 - 9.5 ------- ----- ------- ------- ------- ------- -------- ------ Total revenues 206.4 148.1 142.4 39.0 2.0 537.9 74.8 612.7 ------- ----- ------- ------- ------- ------- -------- ------ Costs and expenses Production expenses 40.3 41.3 30.8 13.2 - 125.6 36.5 162.1 Exploration costs charged to expense 34.9 12.8 3.9 - 8.0 59.6 - 59.6 Undeveloped lease amortization 7.0 4.0 - - - 11.0 - 11.0 Depreciation, depletion and amortization 65.1 43.8 42.8 8.0 .1 159.8 7.1 166.9 Selling and general expenses 13.5 5.6 3.2 .1 1.1 23.5 - 23.5 Gain on disputed transportation - - - (4.9) - (4.9) - (4.9) ------- ----- ------- ------- ------- ------- -------- ------ Total costs and expenses 160.8 107.5 80.7 16.4 9.2 374.6 43.6 418.2 ------- ----- ------- ------- ------- ------- -------- ------ 45.6 40.6 61.7 22.6 (7.2) 163.3 31.2 194.5 Income tax expense 10.3 14.3 24.5 - .5 49.6 10.5 60.1 ------- ----- ------- ------- ------- ------- -------- ------ Results of operations/1/ $ 35.3 26.3 37.2 22.6 (7.7) 113.7 20.7 134.4 ======= ===== ======= ======= ======= ======= ======== ====== </TABLE> /1/ Excludes corporate overhead and interest in 2000 and 1999 and cumulative effect of accounting change in 2000. /2/ Includes $3.3 from gain on disputed contractual item in Ecuador. F-27
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) <TABLE> <CAPTION> Synthetic United United Oil - (Millions of dollars) States Canada Kingdom Ecuador Other Subtotal Canada Total ------ ------ ------- ------- ----- -------- ------ ----- <S> <C> <C> <C> <C> <C> <C> <C> <C> 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 3.5 50.3 58.0 24.2 - 136.0 17.6 153.6 Natural gas Sales to unaffiliated enterprises 136.3 25.1 10.0 - - 171.4 - 171.4 ------- ----- ------- ------- ------- ------- -------- ------ Total oil and gas revenues 172.2 82.5 80.3 24.2 - 359.2 53.0 412.2 Other operating revenues/1/ 11.4 2.7 14.8 2.2 2.7 33.8 (.1) 33.7 ------- ----- ------- ------- ------- ------- -------- ------ Total revenues 183.6 85.2 95.1 26.4 2.7 393.0 52.9 445.9 ------- ----- ------- ------- ------- ------- -------- ------ Costs and expenses Production expenses 48.1 36.9 35.7 12.1 - 132.8 34.5 167.3 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 38.3 42.9 10.2 - 157.4 6.2 163.6 Impairment of properties 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 183.0 116.1 110.0 22.4 37.7 469.2 40.8 510.0 ------- ----- ------- ------- ------- ------- -------- ------ .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) ======= ===== ======= ======= ======= ======= ======== ====== </TABLE> /1/ Includes pretax gains of $4 from settlement of a U.K. long-term sales contract and $2.4 from disputed contractual items in Ecuador. /2/ Excludes corporate overhead and interest. Schedule 5 - Capitalized Costs Relating to Oil and Gas Producing Activities <TABLE> <CAPTION> Synthetic United United Oil - (Millions of dollars) States Canada Kingdom Ecuador Other Subtotal Canada Total ------ ------ ------- ------- ----- -------- ------ ----- <S> <C> <C> <C> <C> <C> <C> <C> <C> December 31, 2000 Unproved oil and gas properties $ 109.9 76.2 .2 - 11.3 197.6 - 197.6 Proved oil and gas properties 1,493.6 1,213.5 805.2 219.0 - 3,731.3 188.5 3,919.8 ------- ------- ----- ----- ------ ------- ----- ------- Gross capitalized costs 1,603.5 1,289.7 805.4 219.0 11.3 3,928.9 188.5 4,117.4 Accumulated depreciation, depletion and amortization Unproved oil and gas properties (38.4) (24.2) (.1) - (3.5) (66.2) - (66.2) Proved oil and gas properties* (1,244.0) (409.8) (601.4) (160.0) - (2,415.2) (37.0) (2,452.2) ------- ------- ----- ----- ------ ------- ----- ------- Net capitalized costs $ 321.1 855.7 203.9 59.0 7.8 1,447.5 151.5 1,599.0 ======= ======= ===== ===== ====== ======= ===== ======= December 31, 1999 Unproved oil and gas properties $ 91.5 37.7 .3 - 3.5 133.0 - 133.0 Proved oil and gas properties 1,453.7 902.6 841.5 206.6 - 3,404.4 176.7 3,581.1 ------- ------- ----- ----- ------ ------- ----- ------- Gross capitalized costs 1,545.2 940.3 841.8 206.6 3.5 3,537.4 176.7 3,714.1 Accumulated depreciation, depletion and amortization Unproved oil and gas properties (34.4) (22.1) (.3) - (3.5) (60.3) - (60.3) Proved oil and gas properties* (1,182.0) (370.0) (609.1) (153.1) - (2,314.2) (31.2) (2,345.4) ------- ------- ----- ----- ------ ------- ----- ------- Net capitalized costs $ 328.8 548.2 232.4 53.5 - 1,162.9 145.5 1,308.4 ======= ======= ===== ===== ====== ======= ===== ======= </TABLE> *Does not include reserve for dismantlement costs of $160 in 2000 and $158.4 in 1999. F-28
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 <TABLE> <CAPTION> United United (Millions of dollars) States Canada* Kingdom Ecuador Total ------ ------ ------- ------- ----- <S> <C> <C> <C> <C> <C> December 31, 2000 Future cash inflows $ 3,479.9 2,860.4 1,209.4 725.5 8,275.2 Future development costs (321.8) (97.3) (55.0) (72.2) (546.3) Future production and abandonment costs (479.2) (615.5) (378.8) (320.4) (1,793.9) Future income taxes (935.6) (673.4) (294.8) (95.6) (1,999.4) ------- -------- -------- --------- ---------- Future net cash flows 1,743.3 1,474.2 480.8 237.3 3,935.6 10% annual discount for estimated timing of cash flows (620.4) (456.1) (153.3) (102.0) (1,331.8) ------- -------- -------- -------- ---------- Standardized measure of discounted future net cash flows $ 1,122.9 1,018.1 327.5 135.3 2,603.8 ======= ======= ======== ======== ========== December 31, 1999 Future cash inflows $ 1,779.1 1,454.2 1,426.4 711.8 5,371.5 Future development costs (210.6) (90.1) (66.0) (48.1) (414.8) Future production and abandonment costs (443.5) (375.6) (417.4) (251.0) (1,487.5) Future income taxes (356.4) (202.8) (315.9) (115.9) (991.0) ------- -------- -------- -------- ---------- Future net cash flows 768.6 785.7 627.1 296.8 2,478.2 10% annual discount for estimated timing of cash flows (271.3) (230.6) (205.5) (119.8) (827.2) ------- -------- ------- -------- ---------- Standardized measure of discounted future net cash flows $ 497.3 555.1 421.6 177.0 1,651.0 ======= ======== ======= ======== ========== </TABLE> *Excludes future net cash flows from synthetic oil of $441.5 at December 31, 2000 and $410.2 at December 31, 1999. Following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown. <TABLE> <CAPTION> (Millions of dollars) 2000 1999 1998 ---- ---- ---- <S> <C> <C> <C> Net changes in prices, production costs and development costs $ 722.0 1,188.2 (894.8) Sales and transfers of oil and gas produced, net of production costs (485.1) (317.9) (132.3) Net change due to extensions and discoveries 544.4 250.0 125.4 Net change due to purchases and sales of proved reserves 519.2 (2.0) 4.5 Development costs incurred 156.6 163.4 165.4 Accretion of discount 229.3 71.9 129.0 Revisions of previous quantity estimates (73.7) 220.7 30.7 Net change in income taxes (659.9) (505.2) 191.0 -------- -------- -------- Net increase (decrease) 952.8 1,069.1 (381.1) Standardized measure at January 1 1,651.0 581.9 963.0 -------- -------- ---------- Standardized measure at December 31 $ 2,603.8 1,651.0 581.9 ======= ======= ========== </TABLE> F-29
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED) <TABLE> <CAPTION> First Second Third Fourth (Millions of dollars except per share amounts) Quarter Quarter Quarter Quarter Year ------- ------- ------- ------- ---- <S> <C> <C> <C> <C> <C> Year Ended December 31, 2000/1/ Sales and other operating revenues $ 1,019.3 1,092.4 1,232.2 1,270.4 4,614.3 Income before income taxes and cumulative effect of accounting change 74.0 119.9 133.0 138.4 465.3 Income before cumulative effect of accounting change 49.1 73.1 90.1 93.2 305.5 Cumulative effect of accounting change (8.7) - - - (8.7) Net income 40.4 73.1 90.1 93.2 296.8 Income per Common share - basic Income before cumulative effect of accounting change 1.09 1.62 2.00 2.07 6.78 Cumulative effect of accounting change (.19) - - - (.19) Net income .90 1.62 2.00 2.07 6.59 Income per Common share - diluted Income before cumulative effect of accounting change 1.09 1.61 1.99 2.06 6.75 Cumulative effect of accounting change (.19) - - - (.19) Net income .90 1.61 1.99 2.06 6.56 Cash dividends per Common share .35 .35 .375 .375 1.45 Market Price of Common Stock/2/ High 63.4375 66.5000 69.0625 68.8750 69.0625 Low 48.1875 54.7500 56.0000 53.3750 48.1875 Year Ended December 31, 1999/1/ Sales and other operating revenues $ 433.5 600.4 811.8 906.4 2,752.1 Income (loss) before income taxes (11.2) 28.2 80.5 81.0 178.5 Net income (loss) (6.7) 15.7 51.2 59.5 119.7 Net income (loss) per Common share - basic (.15) .35 1.14 1.32 2.66 Net income (loss) per Common share - diluted (.15) .35 1.14 1.32 2.66 Cash dividends per Common share .35 .35 .35 .35 1.40 Market Price of Common Stock/2/ High 42.6250 50.9375 54.6250 61.5625 61.5625 Low 32.8750 41.3750 47.6875 51.2500 32.8750 </TABLE> /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 2000 ---- Quarterly totals $ - 1.5 1.9 (1.9) 1.5 Per Common share - basic - .03 .04 (.04) .03 Per Common share - diluted - .03 .04 (.04) .03 1999 ---- Quarterly totals $ (1.0) - 6.3 14.4 19.7 Per Common share - basic (.02) - .14 .32 .44 Per Common share - diluted (.02) - .14 .32 .44 /2/ Prices are as quoted on the New York Stock Exchange. F-30