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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, 2004
OR
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 1-8590
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)
| Delaware | 71-0361522 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number) |
| 200 Peach Street, P.O. Box 7000, El Dorado, Arkansas | 71731-7000 | |
| (Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code: (870) 862-6411
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Name of each exchange on which registered | |
| Common Stock, $1.00 Par Value | New York Stock Exchange |
| Series A Participating Cumulative | New York Stock Exchange | |
| Preferred Stock Purchase Rights |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes x No ¨.
Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on average price at June 30, 2004, as quoted by the New York Stock Exchange, was approximately $6,725,984,000.
Number of shares of Common Stock, $1.00 Par Value, outstanding at January 31, 2005 was 92,034,083.
Documents incorporated by reference:
Portions of the Registrant’s definitive Proxy Statement relating to the Annual Meeting of Stockholders on May 11, 2005 have been incorporated by reference in Part III herein.
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MURPHY OIL CORPORATION
TABLE OF CONTENTS – 2004 FORM 10-K
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Items 1. and 2. BUSINESS AND PROPERTIES
Summary
Murphy Oil Corporation is a worldwide oil and gas exploration and production company with refining and marketing operations in North America and the United Kingdom. As used in this report, the terms Murphy, Murphy Oil, we, our, its and Company may refer to Murphy Oil Corporation or any one or more of its consolidated subsidiaries.
The Company was originally incorporated in Louisiana in 1950 as Murphy Corporation. It was reincorporated in Delaware in 1964, at which time it adopted the name Murphy Oil Corporation, and was reorganized in 1983 to operate primarily as a holding company of its various businesses. Its operations are classified into two business activities: (1) “Exploration and Production” and (2) “Refining and Marketing.” For reporting purposes, Murphy’s exploration and production activities are subdivided into six geographic segments, including the United States, Canada, the United Kingdom, Ecuador, Malaysia and all other countries. Murphy’s refining and marketing activities are subdivided into geographic segments for North America and United Kingdom. Additionally, “Corporate and Other Activities” include interest income, interest expense, foreign exchange effects and overhead not allocated to the segments.
The information appearing in the 2004 Annual Report to Security Holders (2004 Annual Report) is incorporated in this Form 10-K report as Exhibit 13 and is deemed to be filed as part of this Form 10-K report as indicated under Items 1, 2 and 7. A narrative of the graphic and image information that appears in the paper format version of Exhibit 13 is included in the electronic Form 10-K document as an appendix to Exhibit 13.
In addition to the following information about each business activity, data about Murphy’s operations, properties and business segments, including revenues by class of products and financial information by geographic area, are provided on pages 9 through 18, F-12, F-27 through F-29, F-34 through F-36, and F-38 of this Form 10-K report and on pages 6 through 14 of the 2004 Annual Report.
Interested parties may access the Company’s public disclosures filed with the Securities and Exchange Commission, including Form 10-K, Form 10-Q, Form 8-K and other documents, by accessing the Investor Relations section of Murphy Oil Corporation’s website at www.murphyoilcorp.com.
Exploration and Production
The Company’s exploration and production business explores for and produces crude oil, natural gas and natural gas liquids worldwide.
During 2004, Murphy’s principal exploration and production activities were conducted in the United States by wholly owned Murphy Exploration & Production Company-USA (Murphy Expro USA), in Ecuador, Malaysia and the Republic of the Congo by wholly owned Murphy Exploration & Production Company-International (Murphy Expro International) and its subsidiaries, in western Canada and offshore eastern Canada by wholly owned Murphy Oil Company Ltd. (MOCL) and its subsidiaries, and in the U.K. North Sea and the Atlantic Margin by wholly owned Murphy Petroleum Limited. Murphy’s crude oil and natural gas liquids production in 2004 was in the United States, Canada, the United Kingdom, Malaysia and Ecuador; its natural gas was produced and sold in the United States, Canada and the United Kingdom. MOCL owns a 5% undivided interest in Syncrude Canada Ltd. in Northern Alberta, the world’s largest producer of synthetic crude oil.
Murphy’s worldwide crude oil, condensate and natural gas liquids production from continuing operations in 2004 averaged 93,634 barrels per day, an increase of 22% compared to 2003. The increase was primarily due to a full year of production in 2004 at the Medusa and Habanero deepwater fields in the Gulf of Mexico and the West Patricia field offshore Sarawak, Malaysia. The Company’s worldwide sales volume of natural gas from continuing operations averaged 109 million cubic feet (MMCF) per day in 2004, down 2% from 2003 levels. The lower natural gas sales were due to production declines in mature producing areas that more than offset higher production from the Medusa and Habanero fields in the deepwater Gulf of Mexico.
Total crude oil, condensate and natural gas liquids production is expected to increase in 2005 because of a full year of production at the Front Runner field in the deepwater Gulf of Mexico and the Seal area in western Canada. Front Runner came on stream in December 2004. Natural gas sales volumes are expected to increase in 2005 compared to 2004 due to the higher production from the three deepwater Gulf of Mexico fields mentioned above.
In the United States, Murphy has production of oil and/or natural gas from 13 fields operated by the Company and 15 fields operated by others. Of the total producing fields at December 31, 2004, four are in the deepwater Gulf of Mexico, 20 are in more shallow waters on the Gulf of Mexico continental shelf, three are onshore in Louisiana and one is the Northstar field in Alaska. The Company’s primary focus in the U.S. is in the deepwater Gulf of Mexico, which is generally defined as water depths of 1,000 feet or more. The Company operates and owns a 60% interest in the Medusa field, in Mississippi Canyon Blocks 538/582. Medusa produced about 12,000 barrels of oil per day and 12 MMCF of gas
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per day net to the Company in 2004. Peak net production from Medusa is expected to be 25,000 barrels of oil equivalent per day. The Company owns a 33.75% interest in the Habanero field in Garden Banks Block 341. Habanero, which is operated by Shell, produced about 4,000 barrels of oil per day and 10 MMCF of gas per day net to the Company in 2004. The Front Runner field in Green Canyon Blocks 338/339 came on stream in December 2004 and will have additional wells completed and hooked up throughout 2005. Murphy owns 37.5% and operates the Front Runner field, which is expected to have peak net production of 20,000 barrels of oil equivalent per day in 2006. Hurricane Ivan caused temporary shut in of wells and damaged certain facilities which ultimately reduced the Company’s annualized production in the U.S. during 2004 by about 4,000 barrels of oil equivalent per day. The other deepwater producing field is at Tahoe in Viosca Knoll Block 783 (30%). Tahoe is operated by Shell and in 2004 produced about 13 MMCF of natural gas per day and 300 barrels of oil per day net to the Company. In 2004, Murphy announced a discovery at the Thunderhawk wildcat well in Mississippi Canyon Block 734 and in early 2005 announced a discovery at South Dachshund in Lloyd Ridge Blocks 1 and 2. Murphy holds an interest in 183 blocks in the deepwater Gulf of Mexico, and expects to drill about four deepwater prospects per year over the next several years. The Company’s largest producing field on the continental shelf of the Gulf of Mexico is at South Timbalier Blocks 63/86 (100%/96%). Murphy operates South Timbalier Blocks 63/86 with a combined net production of about 400 barrels of oil per day and 10 MMCF per day in 2004. Onshore production, which is mostly natural gas, is primarily located on several leases in Vermilion Parish, Louisiana. Murphy’s net production in 2004 from onshore fields was 26 MMCF per day. The Company owns approximately a 1.4% working interest in the Northstar field operated by BP in Alaska. Total net oil production for this field was approximately 800 barrels per day in 2004.
In Canada, the Company owns an interest in three legacy assets, the Hibernia and Terra Nova fields offshore Newfoundland and Syncrude Canada Ltd. In addition, the Company owned interests in two heavy oil areas and one natural gas area in the Western Canada Sedimentary Basin (WCSB) at the end of 2004. In the second quarter 2004, the Company completed the sale of most of its WCSB assets, while retaining a limited number of heavy oil and natural gas fields which are strategic to the Company. Assets sold produced about 20,000 barrels of oil equivalent per day in 2003 and had total proved reserves of approximately 43 million barrels of oil equivalent at the time of sale. In late 2004, Murphy acquired additional acreage in the Seal heavy oil area at a cost of $121 million. Murphy holds a 6.5% interest in Hibernia and a 12% interest in Terra Nova, with these being the first two fields on production in the Jeanne d’Arc Basin, offshore Newfoundland. Total net production in 2004 was 12,700 barrels of oil per day from Hibernia, which is operated by Hibernia Management and Development Company, while net production from Terra Nova, which is operated by PetroCanada, was also 12,700 barrels of oil per day. Murphy owns a 5% undivided interest in Syncrude Canada Ltd., a joint venture located about 25 miles north of Fort McMurray, Alberta. Syncrude utilizes its assets to extract bitumen from oil sand deposits and to upgrade this bitumen into a high-value synthetic crude oil. Syncrude is currently expanding its facilities and is adding a third coker that will allow for increased production beginning in 2006. Total net production in 2004 was 11,800 barrels of crude oil per day, but with the expansion net production is expected to exceed 15,000 barrels per day in 2006. Although Syncrude produces a very high quality synthetic crude oil from bitumen, the U.S. Securities and Exchange Commission (SEC) does not allow the Company to include Syncrude’s reserves in its proved oil reserves, which are reported on page F-32. The SEC considers Syncrude to be a mining operation, and not a conventional oil operation.
Murphy produces oil and natural gas in the United Kingdom sector of the North Sea. The Company’s primary oil production in the U.K. is now derived from two areas, Schiehallion and Mungo/Monan. Murphy owns 5.88% of the Schiehallion field operated by BP. This field is located in an area known as the Atlantic Margin and lies west of the Shetland Islands. Schiehallion produces oil into a Floating Production Storage and Offloading vessel (FPSO). The oil is transported via dedicated tanker to Sullom Voe terminal, where the oil is sold to third parties. Schiehallion produced approximately 5,300 net barrels of oil per day in 2004. Schiehallion development will continue with further infield drilling planned in 2005 onwards. Murphy owns a 4.843% interest in the FPSO, which also handles production from a nearby field owned by others. Mungo/Monan is also operated by BP and is 12.65% owned by Murphy. The Mungo field produces through an unmanned platform, while Monan is produced through subsea facilities. Both the platform and subsea facilities are tied to a central processing facility that is linked to the Forties pipeline system. In 2004, the Mungo and Monan fields produced approximately 4,500 barrels of oil per day, net to Murphy’s interest. In 2004, the Company sold its interest in the “T” Block field. Production from this field averaged about 1,600 net barrels per day in 2004 prior to the sale.
In Ecuador, Murphy owns a 20% working interest in Block 16, which is operated by Repsol YPF under a participation contract. The Company’s net production was about 7,700 barrels of oil per day in 2004. Between June and December 2004, Murphy did not receive its equity share of oil sales from Block 16 due to a dispute with the operator involving the Company’s new transportation and marketing arrangements. Murphy is owed more than 1.5 million barrels from other Block 16 working interest owners as of December 31, 2004. Murphy expects to make up this shortfall owed by the other owners in 2005 by either a cash settlement or an allocation of additional 2005 production barrels to the Company.
The Company has majority interests in eight separate production sharing contracts (PSCs) in Malaysia. The Company serves as the operator of all these areas, which cover approximately 14.4 million acres in total. Murphy has an 85% interest in two shallow water blocks, known as SK 309 and SK 311. The West Patricia field in Block SK 309, discovered in 2002, came on stream in May 2003. The Company’s net share of production averaged about 11,900 barrels of oil per day in 2004. The Company made a major discovery at the Kikeh field in deepwater Block K in 2002 and added a discovery at Kikeh Kecil in 2003 and discoveries at Kakap, Senangin and Kikeh deep formation in 2004. Further exploration and appraisal drilling will occur in the 80% owned Block K in 2005. In 2004, our Board of Directors and Malaysian authorities sanctioned the Kikeh field development plan, and in early 2005 engineering and construction contracts for major equipment were awarded. The Company added proved oil reserves of 40.5 million barrels related to the Kikeh field in Block K Malaysia at year-end 2004. These proved reserves did not include any volumes attributable to pressure maintenance programs that the Company intends to utilize to produce the Kikeh field when
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production begins, which is currently projected to be in the second half of 2007. Murphy also owns 75% interests in Blocks PM 311 and PM 312, located offshore peninsular Malaysia. Murphy announced discoveries at Kenarong and Pertang in PM 311 in 2004. The Company has a number of exploration prospects in Block H (80%) in deepwater. The Company was awarded interests in PSCs covering deepwater Blocks L (60%) and M (70%) in early 2003. The Sultanate of Brunei also claims this acreage. Murphy drilled a wildcat well in Block L in mid-2003. Well results have been kept confidential and well costs of $12 million are held in suspension pending the resolution of the ownership issue. The Company is unable to predict when the ownership issue will be resolved or the outcome of such a resolution. A total of 2.9 million gross acres associated with Blocks L and M have been included in the acreage table below.
The Company finalized the award of Production Sharing Agreements (PSAs) covering two offshore blocks in the Republic of the Congo in 2004. The Company has an 85% interest in each PSA. These blocks are named Mer Profonde Sud and Mer Profonde Nord, and together, these blocks cover approximately 1.8 million acres with water depths ranging from 490 to 6,900 feet. Murphy drilled its first exploration well in late 2004 and in early 2005 announced a significant oil discovery at Azurite Marine #1 in Mer Profonde Sud.
Murphy’s estimated net quantities of proved oil and gas reserves and proved developed oil and gas reserves at December 31, 2001, 2002, 2003 and 2004 by geographic area are reported on pages F-31 and F-32 of this Form 10-K report. Murphy has not filed and is not required to file any estimates of its total net proved oil or gas reserves on a recurring basis with any federal or foreign governmental regulatory authority or agency other than the U.S. Securities and Exchange Commission. Annually, Murphy reports gross reserves of properties operated in the United States to the U.S. Department of Energy; such reserves are derived from the same data from which estimated net proved reserves of such properties are determined.
Net crude oil, condensate, and gas liquids production and sales, and net natural gas sales by geographic area with weighted average sales prices for each of the five years ended December 31, 2004 are shown on page 8 of the 2004 Annual Report.
Production expenses for the last three years in U.S. dollars per equivalent barrel are discussed on page 14 of this Form 10-K report. For purposes of these computations, natural gas sales volumes are converted to equivalent barrels of crude oil using a ratio of six thousand cubic feet (MCF) of natural gas to one barrel of crude oil.
Supplemental disclosures relating to oil and gas producing activities are reported on pages F-30 through F-38 of this Form 10-K report.
At December 31, 2004, Murphy held leases, concessions, contracts or permits on developed and undeveloped acreage as shown by geographic area in the following table. Gross acres are those in which all or part of the working interest is owned by Murphy. Net acres are the portions of the gross acres attributable to Murphy’s working interest.
| Developed | Undeveloped | Total | ||||||||||
Area (Thousands of acres)1 | Gross | Net | Gross | Net | Gross | Net | ||||||
United States – Onshore | 5 | 2 | 206 | 87 | 211 | 89 | ||||||
– Gulf of Mexico | 22 | 7 | 1,310 | 851 | 1,332 | 858 | ||||||
– Alaska | 3 | —1 | 9 | 2 | 12 | 2 | ||||||
Total United States | 30 | 9 | 1,525 | 940 | 1,555 | 949 | ||||||
Canada – Onshore | 65 | 44 | 228 | 191 | 293 | 235 | ||||||
– Offshore | 88 | 7 | 8,504 | 2,661 | 8,592 | 2,668 | ||||||
Total Canada | 153 | 51 | 8,732 | 2,852 | 8,885 | 2,903 | ||||||
United Kingdom | 33 | 4 | 328 | 77 | 361 | 81 | ||||||
Ecuador | 7 | 1 | 524 | 105 | 531 | 106 | ||||||
Malaysia | 2 | 2 | 14,4312 | 11,1002 | 14,4332 | 11,1022 | ||||||
Republic of Congo | — | — | 1,773 | 1,507 | 1,773 | 1,507 | ||||||
Ireland | — | — | 325 | 49 | 325 | 49 | ||||||
Spain | — | — | 36 | 6 | 36 | 6 | ||||||
Totals | 225 | 67 | 27,674 | 16,636 | 27,899 | 16,703 | ||||||
Oil sands – Syncrude | 95 | 5 | 158 | 8 | 253 | 13 | ||||||
| 1 | Less than one. |
| 2 | Includes 2,935 gross acres and 1,910 net acres in Blocks L and M, which were awarded to the Company by Malaysia, but also have been claimed by the Sultanate of Brunei. |
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The only significant undeveloped acreage that expires in the next three years is approximately 9.5 million net acres in Malaysia and .9 million acres offshore the East Coast of Canada. The Company is currently negotiating to extend the exploration rights for the Malaysian acreage.
As used in the three tables that follow, “gross” wells are the total wells in which all or part of the working interest is owned by Murphy, and “net” wells are the total of the Company’s fractional working interests in gross wells expressed as the equivalent number of wholly owned wells.
The following table shows the number of oil and gas wells producing or capable of producing at December 31, 2004.
| Oil Wells | Gas Wells | |||||||
Country | Gross | Net | Gross | Net | ||||
United States | 119 | 26 | 120 | 46 | ||||
Canada | 381 | 262 | 60 | 40 | ||||
United Kingdom | 29 | 3 | 22 | 2 | ||||
Malaysia | 17 | 14 | — | — | ||||
Ecuador | 115 | 23 | — | — | ||||
Totals | 661 | 328 | 202 | 88 | ||||
Wells included above with multiple completions and counted as one well each | 15 | 8 | 29 | 12 | ||||
Murphy’s net wells drilled in the last three years are shown in the following table.
United States | Canada | United Kingdom | Malaysia | Ecuador and Other | Totals | |||||||||||||||||||
| Productive | Dry | Productive | Dry | Productive | Dry | Productive | Dry | Productive | Dry | Productive | Dry | |||||||||||||
2004 | ||||||||||||||||||||||||
Exploratory | 1.3 | 2.0 | 4.6 | 1.4 | — | .1 | 6.0 | 5.8 | — | — | 11.9 | 9.3 | ||||||||||||
Development | 1.0 | — | 84.1 | 25.0 | — | — | 7.7 | — | 2.8 | — | 95.6 | 25.0 | ||||||||||||
2003 | ||||||||||||||||||||||||
Exploratory | 2.5 | 2.4 | 10.4 | 9.4 | — | — | .8 | 2.7 | — | .1 | 13.7 | 14.6 | ||||||||||||
Development | 2.4 | — | 108.2 | 3.9 | .2 | .3 | 4.1 | — | 2.4 | — | 117.3 | 4.2 | ||||||||||||
2002 | ||||||||||||||||||||||||
Exploratory | 1.0 | 3.2 | 8.8 | 4.1 | — | .5 | 4.3 | 3.7 | — | — | 14.1 | 11.5 | ||||||||||||
Development | 2.2 | — | 45.5 | 3.9 | .7 | .2 | 3.4 | — | 3.4 | — | 55.2 | 4.1 | ||||||||||||
The increase in the number of development dry hole wells in Canada in 2004 was caused by 23 nonproducing stratigraphic wells drilled in the Seal area for the purpose of placement of horizontal development wells for the field.
Murphy’s drilling wells in progress at December 31, 2004 are shown below.
| Exploratory | Development | Total | ||||||||||
Country | Gross | Net | Gross | Net | Gross | Net | ||||||
United States | 3.0 | .6 | — | — | 3.0 | .6 | ||||||
Canada | — | — | 4.0 | .8 | 4.0 | .8 | ||||||
Malaysia | 2.0 | 1.6 | — | — | 2.0 | 1.6 | ||||||
Republic of Congo | 1.0 | 1.0 | — | — | 1.0 | 1.0 | ||||||
Ecuador | — | — | 1.0 | .2 | 1.0 | .2 | ||||||
Totals | 6.0 | 3.2 | 5.0 | 1.0 | 11.0 | 4.2 | ||||||
Additional information about current exploration and production activities is reported on pages 5 through 10 of the 2004 Annual Report.
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Refining and Marketing
The Company’s refining and marketing businesses are located in North America and the United Kingdom, and primarily consist of operations that refine crude oil and other feedstocks into petroleum products such as gasoline and distillates, buy and sell crude oil and refined products, and transport and market petroleum products.
Murphy Oil USA, Inc. (MOUSA), a wholly owned subsidiary of Murphy Oil Corporation, owns and operates two refineries in the United States. The Meraux, Louisiana refinery is located on fee land and on two leases that expire in 2010 and 2021, at which times the Company has options to purchase the leased acreage at fixed prices. The refinery at Superior, Wisconsin is located on fee land. Murco Petroleum Limited (Murco), a wholly owned U.K. subsidiary serviced by Murphy Eastern Oil Company, has an effective 30% interest in a refinery at Milford Haven, Wales that can process 108,000 barrels of crude oil per day. Refinery capacities at December 31, 2004 are shown in the following table.
| Meraux, Louisiana | Superior, Wisconsin | Milford Haven, Wales (Murco’s 30%) | Total | |||||
Crude capacity – b/sd* | 125,000 | 35,000 | 32,400 | 192,400 | ||||
Process capacity – b/sd* | ||||||||
Vacuum distillation | 50,000 | 20,500 | 16,500 | 87,000 | ||||
Catalytic cracking – fresh feed | 37,000 | 11,000 | 9,960 | 57,960 | ||||
Naphtha hydrotreating | 35,000 | 9,000 | 5,490 | 49,490 | ||||
Catalytic reforming | 32,000 | 8,000 | 5,490 | 45,490 | ||||
Gasoline hydrotreating | — | 7,500 | — | 7,500 | ||||
Distillate hydrotreating | 52,000 | 7,800 | 20,250 | 80,050 | ||||
Hydrocracking | 32,000 | — | — | 32,000 | ||||
Gas oil hydrotreating | 12,000 | — | — | 12,000 | ||||
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 | 4,336,000 | 3,085,000 | 2,638,000 | 10,059,000 | ||||
| * | Barrels per stream day. |
Murphy has expanded the Meraux refinery allowing the refinery to now meet new low-sulfur gasoline specifications which become effective for the Company in 2008. The expansion included a new hydrocracker unit, central control room and two new utility boilers; expansion of the crude oil processing capacity to 125,000 barrels per stream day (b/sd); expansion of naphtha hydrotreating capacity to 35,000 b/sd; expansion of the catalytic reforming capacity to 32,000 b/sd; and construction of a new sulfur recovery complex, including amine regeneration, sour water stripping and high efficiency sulfur recovery. The Meraux plant had no solvent deasphalting processing capability during 2004 because of the fire in June 2003 that destroyed the Residual Oil Supercritical Extractor (ROSE) unit. The ROSE unit has been rebuilt, primarily using proceeds of property insurance, and was restarted in early 2005. While the ROSE unit was being rebuilt, the refinery produced a larger volume of heavy fuel oil. During 2004 the Company also completed an FCC gasoline hydrotreater unit at its Superior, Wisconsin refinery, that allows the refinery to meet low-sulfur gasoline specifications.
MOUSA markets refined products through a network of retail gasoline stations and branded and unbranded wholesale customers in a 23-state area of the southern and midwestern United States. Murphy’s retail stations are primarily located in the parking areas of Wal-Mart stores in 21 states and use the brand name Murphy USA®. Branded wholesale customers use the brand name SPUR®. Refined products are supplied from 11 terminals that are wholly owned and operated by MOUSA, one terminal that is jointly owned and operated by others, and numerous terminals owned by others. Of the wholly owned terminals, three are supplied by marine transportation, three are supplied by truck, three are supplied by pipeline and two are adjacent to MOUSA’s refineries. MOUSA receives products at the terminals owned by others either in exchange for deliveries from the Company’s terminals or by outright purchase. The Company sold all but one of its jointly owned terminals in early 2004. At December 31, 2004, the Company marketed products through 752 Murphy USA stations and 366 branded wholesale SPUR stations. MOUSA plans to add about 150 new Murphy USA stations at Wal-Mart sites in the southern and midwestern United States in 2005. The Company’s Canadian subsidiary operates eight Murphy CanadaTMstations at Wal-Mart sites in Canada.
Murphy has master agreements that allow the Company to rent space in the parking lots of Wal-Mart stores in 21 states and in Canada for the purpose of building retail gasoline stations. The master agreements contain general terms applicable to all sites in the United States and Canada. As each individual station is constructed, an addendum to the master agreement is entered into, which contains the terms specific to
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that location. The terms of the agreements range from 10-15 years at each station, with Murphy holding two successive five-year extension options at each site. The agreements permit Wal-Mart to terminate the agreements in their entirety, or only as to affected sites, at its option for the following reasons: Murphy vacates or abandons the property; Murphy improperly transfers the rights under this agreement to another party; an agreement or a premises is taken upon execution or by process of law; Murphy files a petition in bankruptcy or becomes insolvent; Murphy fails to pay its debts as they become due; Murphy fails to pay rent or other sums required to be paid within 90 days after written notice; or Murphy fails to perform in any material way as required by the agreements. Sales from these stations amounted to 38.6% of total Company revenues in 2004, 35.8% in 2003 and 30.3% in 2002. As the Company continues to expand the number of gasoline stations at Wal-Mart sites, total revenue generated by this business is expected to grow.
At the end of 2004, Murco distributed refined products in the United Kingdom from the Milford Haven refinery, three wholly owned terminals supplied by rail, six terminals owned by others where products are received in exchange for deliveries from the Company’s terminals, and 358 branded stations primarily under the brand name MURCO.
Murphy owns a 20% interest in a 120-mile refined products pipeline, with a capacity of 165,000 barrels a day, that transports products from the Meraux refinery to two common carrier pipelines serving the southeastern United States. The Company also owns a 3.2% interest in LOOP LLC, which provides deepwater unloading accommodations off the Louisiana coast for oil tankers and onshore facilities for storage of crude oil. A crude oil pipeline with a diameter of 24 inches connects LOOP storage at Clovelly, Louisiana to the Meraux refinery. Murphy owns 29.4% of the first 22 miles of this pipeline from Clovelly to Alliance, Louisiana and 100% of the remaining 24 miles from Alliance to Meraux. The pipeline is connected to another company’s pipeline system, allowing crude oil transported by that system to also be shipped to the Meraux refinery. In February 2002, the Company sold its 22% interest in a 312-mile crude oil pipeline in Montana and Wyoming for $7 million.
Additional information about current refining and marketing activities and a statistical summary of key operating and financial indicators for each of the five years ended December 31, 2004 are reported on pages 11 through 14 of the 2004 Annual Report.
Employees
At December 31, 2004, Murphy had 5,826 employees – 2,139 full-time and 3,687 part-time.
Competition and Other Conditions Which May Affect Business
Murphy operates in the oil industry and experiences intense competition from other oil companies, which include state-owned foreign oil companies, major integrated oil companies, independent producers of oil and natural gas and independent refining companies. Virtually all of the state-owned and major integrated oil companies and many of the independent producers and independent refiners that compete with the Company have substantially greater resources than Murphy. In addition, the oil industry as a whole competes with other industries in supplying energy requirements around the world. Murphy is a net purchaser of crude oil and other refinery feedstocks, and also purchases refined products, particularly gasoline needed to supply its retail marketing stations located at Wal-Mart sites. The Company may be required to respond to operating and pricing policies of others, including producing country governments from whom it makes purchases. Additional information concerning current conditions of the Company’s business is reported under the caption “Outlook” beginning on page 22 of this Form 10-K report.
In 2004, the Company’s production of oil and natural gas represented approximately .1% of the respective worldwide totals. Murphy owned approximately 1% of the crude oil refining capacity in the United States and its market share of U.S. retail gasoline sales was approximately 1.4%.
The operations and earnings of Murphy have been and continue to be affected by worldwide political developments. Many governments, including those that are members of the Organization of Petroleum Exporting Countries (OPEC), unilaterally intervene at times in the orderly market of crude oil and natural gas produced in their countries through such actions as setting prices, determining rates of production, and controlling who may buy and sell the production.
In addition, prices and availability of crude oil, natural gas and refined products could be influenced by political unrest and by various governmental policies to restrict or increase petroleum usage and supply. Other governmental actions that could affect Murphy’s operations and earnings include tax changes and regulations concerning: currency fluctuations, protection and remediation of the environment (See the caption “Environmental” beginning on page 18 of this Form 10-K report), preferential and discriminatory awarding of oil and gas leases, restrictions on drilling and/or production, restraints and controls on imports and exports, safety, and relationships between employers and employees. Because these and other factors too numerous to list are subject to changes caused by governmental and political considerations and are often made in response to changing internal and worldwide economic conditions and to actions of other governments or specific events, it is not practical to attempt to predict the effects of such factors on Murphy’s future operations and earnings.
Murphy’s business is subject to operational hazards and risks normally associated with the exploration for and production of oil and natural gas and the refining and marketing of crude oil and petroleum products. The occurrence of an event, including but not limited to acts of nature, mechanical equipment failures, industrial accidents, fires and intentional attacks could result in the loss of hydrocarbons and associated revenues, environmental pollution or contamination, and personal injury or bodily injury, including death, for which the Company
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could be deemed to be liable, and could subject the Company to substantial fines and/or claims for punitive damages. Murphy maintains insurance against certain, but not all, hazards that could arise from its operations, and such insurance is believed to be reasonable for the hazards and risks faced by the Company. As of December 31, 2004, the Company maintained total excess liability insurance with limits of $750 million per occurrence covering employees, general liability and certain “sudden and accidental” environmental risks. The Company also maintained insurance coverage with an additional limit of $250 million per occurrence, all or part of which could be applicable to certain gradual and/or sudden and accidental pollution events. There can be no assurance that such insurance will be adequate to offset lost revenues or costs associated with certain events or that insurance coverage will continue to be available in the future on terms that justify its purchase. The occurrence of an event that is not fully insured could have a material adverse effect on the Company’s financial condition and results of operations in the future.
Executive Officers of the Registrant
The age at January 1, 2005, present corporate office and length of service in office of each of the Company’s executive officers are reported in the following listing. Executive officers are elected annually but may be removed from office at any time by the Board of Directors.
Claiborne P. Deming – Age 50; President and Chief Executive Officer since October 1994 and Director and Member of the Executive Committee since 1993.
Steven A. Cossé – Age 57; Executive Vice President since February 2005 and General Counsel since August 1991. Mr. Cossé was elected Senior Vice President in 1994 and Vice President in 1993.
W. Michael Hulse – Age 51; Executive Vice President – Worldwide Downstream Operations effective April 2003. Mr. Hulse has been President of MOUSA from November 2001 to present. He served as President of Murphy Eastern Oil Company from April 1996 to November 2001.
Bill H. Stobaugh – Age 53; Senior Vice President since February 2005. Mr. Stobaugh joined the Company as Vice President in 1995.
Kevin G. Fitzgerald – Age 49; Treasurer since July 2001. Mr. Fitzgerald was Director of Investor Relations from 1996 to June 2001.
John W. Eckart – Age 46; Controller since March 2000.
Walter K. Compton – Age 42; Secretary since December 1996.
In December 2000, two of the Company’s Canadian subsidiaries, Murphy Oil Company Ltd. (MOCL) and Murphy Canada Exploration Company (MCEC) as plaintiffs filed an action in the Court of Queen’s Bench of Alberta seeking a constructive trust over oil and gas leasehold rights to Crown lands in British Columbia. The suit alleges that the defendants, the Predator Corporation Ltd. and Predator Energies Partnership (collectively Predator) and Ricks Nova Scotia Co. (Ricks), acquired the lands after first inappropriately obtaining confidential and proprietary data belonging to the Company and its partner. In January 2001, Ricks, representing an undivided 75% interest in the lands in question, settled its portion of the litigation by conveying its interest to the Company and its partner at cost. In 2001, Predator, representing the remaining undivided 25% of the lands in question, filed a counterclaim, as subsequently amended, against MOCL and MCEC and MOCL’s president individually seeking compensatory damages of C$3.61 billion. In September 2004 the court summarily dismissed all claims against MOCL’s president and all but C$356 million of the counterclaim against the Company; however, this dismissal order is currently on appeal. It is anticipated that a trial concerning the 25% disputed interest and any remaining issues will commence in 2005. While the litigation is in the discovery stage and no assurance can be given about the outcome, the Company does not believe that the ultimate resolution of this suit will have a material adverse effect on its net income, financial condition or liquidity in a future period. In the unlikely event that Predator were to prevail in its counterclaim in an amount approaching the damages sought, Murphy would incur a material expense in its consolidated statement of income, and would have a material effect on its financial condition and liquidity.
On June 10, 2003, a fire severely damaged the Residual Oil Supercritical Extraction (ROSE) unit at the Company’s Meraux, Louisiana refinery. The ROSE unit recovers feedstock from the heavy fuel oil stream for conversion into gasoline and diesel. Subsequent to the fire, numerous class action lawsuits have been filed seeking damages for area residents. All the lawsuits have been administratively consolidated into a single legal action in St. Bernard Parish, Louisiana, except for one such action which was filed in federal court. Additionally, individual residents of Orleans Parish, Louisiana, have filed an action in that venue. On May 5, 2004, plaintiffs in the consolidated action in St. Bernard Parish amended their petition to include a direct action against certain of the Company’s liability insurers. In responding to this direct action, one of the Company’s insurers, AEGIS, has raised lack of coverage as a defense. The Company believes that this contention lacks merit and has been advised by counsel that the applicable policy does provide coverage for the underlying incident. Because the Company believes that insurance coverage exists for this matter, it does not expect to incur any significant costs associated with the class action lawsuits. Accordingly, the Company continues to believe that the ultimate resolution of the June 2003 ROSE fire litigation will not have a material adverse effect on its net income, financial condition or liquidity in a future period.
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On March 5, 2002, two of the Company’s subsidiaries filed suit against Enron Canada Corp. (Enron) to collect approximately $2.1 million owed to Murphy under canceled gas sales contracts. On May 1, 2002, Enron counterclaimed for approximately $19.8 million allegedly owed by Murphy under those same agreements. Although the lawsuit in the Court of Queen’s Bench, Alberta, is in its early stages and no assurance can be given about the outcome, the Company does not believe that the Enron counterclaim is meritorious and does not believe that the ultimate resolution of this matter will have a material adverse effect on its net income, financial condition or liquidity in a future period. In the unlikely event that Enron were to prevail in the lawsuit, the Company could incur expense in a future period approximating the amount of the judgment.
Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of matters referred to in this item is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth quarter of 2004.
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The Company’s Common Stock is traded on the New York Stock Exchange using “MUR” as the trading symbol. There were 2,864 stockholders of record as of December 31, 2004. Information as to high and low market prices per share and dividends per share by quarter for 2004 and 2003 are reported on page F-38 of this Form 10-K report.
Item 6. SELECTED FINANCIAL DATA
(Thousands of dollars except per share data) | 2004 | 2003 | 2002 | 2001 | 2000 | ||||||
Results of Operations for the Year | |||||||||||
Sales and other operating revenues* | $ | 8,299,147 | 5,094,518 | 3,779,381 | 3,579,143 | 3,548,125 | |||||
Net cash provided by continuing operations | 1,035,057 | 501,127 | 372,205 | 491,326 | 644,391 | ||||||
Income from continuing operations | 496,395 | 278,410 | 87,279 | 296,563 | 272,312 | ||||||
Net income | 701,315 | 294,197 | 111,508 | 330,903 | 296,828 | ||||||
Per Common share – diluted | |||||||||||
Income from continuing operations | 5.31 | 3.00 | .95 | 3.25 | 3.01 | ||||||
Net income | 7.51 | 3.17 | 1.21 | 3.63 | 3.28 | ||||||
Cash dividends per Common share | .85 | .80 | .775 | .75 | .725 | ||||||
Percentage return on | |||||||||||
Average stockholders’ equity | 31.3 | 16.4 | 7.3 | 23.5 | 26.4 | ||||||
Average borrowed and invested capital | 21.8 | 11.0 | 5.8 | 17.7 | 20.3 | ||||||
Average total assets | 13.5 | 6.7 | 3.9 | 10.2 | 11.2 | ||||||
Capital Expenditures for the Year | |||||||||||
Continuing operations | |||||||||||
Exploration and production | $ | 839,182 | 689,632 | 538,994 | 500,726 | 320,733 | |||||
Refining and marketing | 134,706 | 215,362 | 234,714 | 175,186 | 153,750 | ||||||
Corporate and other | 1,505 | 1,120 | 1,136 | 5,806 | 11,415 | ||||||
| 975,393 | 906,114 | 774,844 | 681,718 | 485,898 | |||||||
Discontinued operations | 9,065 | 73,050 | 93,256 | 182,722 | 71,999 | ||||||
| $ | 984,458 | 979,164 | 868,100 | 864,440 | 557,897 | ||||||
Financial Condition at December 31 | |||||||||||
Current ratio | 1.35 | 1.28 | 1.19 | 1.07 | 1.10 | ||||||
Working capital | $ | 424,372 | 228,529 | 136,268 | 38,604 | 71,710 | |||||
Net property, plant and equipment | 3,685,594 | 3,530,800 | 2,886,599 | 2,525,807 | 2,184,719 | ||||||
Total assets | 5,458,243 | 4,712,647 | 3,885,775 | 3,259,099 | 3,134,353 | ||||||
Long-term debt | 613,355 | 1,090,307 | 862,808 | 520,785 | 524,759 | ||||||
Stockholders’ equity | 2,649,156 | 1,950,883 | 1,593,553 | 1,498,163 | 1,259,560 | ||||||
Per share | 28.78 | 21.24 | 17.38 | 16.53 | 13.98 | ||||||
Long-term debt – percent of capital employed | 18.8 | 35.9 | 35.1 | 25.8 | 29.4 | ||||||
| * | Sales and other operating revenues for 2000–2003 have been revised to conform to 2004 presentation. |
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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
Murphy Oil Corporation is a worldwide oil and gas exploration and production company with refining and marketing operations in North America and the United Kingdom. A more detailed description of the Company’s significant assets can be found in Items 1 and 2 of this Form 10-K report.
Murphy generates revenue primarily by selling its oil and natural gas production and its refined petroleum products to customers at hundreds of locations in the United States, Canada, the United Kingdom and other countries. The Company’s revenue is highly affected by the prices of oil, natural gas and refined petroleum products it sells. Also, because crude oil is purchased by the Company for refinery feedstocks, natural gas is purchased for fuel at its refineries and oil fields, and gasoline is purchased to supply its retail gasoline stations in North America that are primarily located at Wal-Mart stores, the purchase prices for these commodities also have a significant effect on the Company’s costs. In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products, amortization of capital expenditures and expenses related to exploration. Profits and generation of cash in the Company’s downstream operations are dependent upon achieving an adequate margin, which is determined by the sales prices for refined petroleum products less the costs of refinery feedstocks and gasoline purchases and expenses associated with manufacturing, transporting and marketing these products. Murphy also incurs certain costs for general company administration and for capital borrowed from lending institutions.
In general, worldwide oil prices and North American natural gas prices were stronger in 2004 than in 2003. The average price for a barrel of West Texas Intermediate crude oil in 2004 was $41.47, an increase of 34% compared to 2003. The NYMEX natural gas price averaged $6.18 per million British Thermal Units (MMBTU) in 2004, up 13% over 2003. These price improvements were a significant factor leading to higher profits in the Company’s exploration and production business in 2004 compared to the prior year. If the prices for crude oil and natural gas decline significantly in 2005 or beyond, the Company would expect this to have an unfavorable impact on operating profits for its exploration and production business. Such lower oil and gas prices could, but may not, have a favorable impact on the Company’s refining and marketing operating profits.
Results of Operations
The Company had net income in 2004 of $701.3 million, $7.51 per diluted share, compared to net income in 2003 of $294.2 million, $3.17 per diluted share. In 2002 the Company earned $111.5 million, $1.21 per diluted share. The higher net income in 2004 compared to 2003 was caused by a combination of better earnings in the Company’s exploration and production and refining and marketing operations, partially offset by higher net costs for corporate functions. The income improvement in 2003 compared to 2002 was due to higher earnings in the exploration and production business, a smaller loss in the refining and marketing area, and lower net costs for corporate functions. Further explanations of each of these variances are found in the following sections.
Each of the three years ended December 31, 2004 included income from discontinued operations. In the second quarter 2004 the Company sold most of its conventional oil and natural gas properties in Western Canada for cash proceeds of $583 million. This sale generated an after-tax gain of $171.1 million. In December 2002 the Company sold its interest in Ship Shoal Block 113 in the Gulf of Mexico, with a resulting after-tax gain of $10.6 million. In accordance with Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the gains on disposal of these assets and operating results for the fields prior to their sale have been included, net of income tax expense, as Discontinued Operations in the consolidated statements of income for the three-year period ended December 31, 2004. Income from discontinued operations was $204.9 million, $2.20 per share, in 2004, $22.8 million, $.25 per share, in 2003, and $24.2 million, $.26 per share, in 2002.
On January 1, 2003, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. Upon adoption of SFAS No. 143, the Company recorded an expense of $7 million, net of $1.4 million in income taxes, as the cumulative effect of a change in accounting principle. Further explanation of this accounting change is included in Note G to the consolidated financial statements. Income before the cumulative effect of a change in accounting principle was $301.2 million, $3.25 per share, in 2003.
Income from continuing operations was $496.4 million, $5.31 per share, in 2004, $278.4 million, $3.00 per share, in 2003, and $87.3 million, $.95 per share, in 2002.
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2004 vs. 2003– Net income in 2004 was $701.3 million, $7.51 per share, compared to $294.2 million, $3.17 per share, in 2003. Both periods included income from discontinued operations associated with conventional oil and natural gas properties in Western Canada that were sold in the second quarter 2004. Income from discontinued operations amounted to $204.9 million in 2004 and $22.8 million in 2003, $2.20 and $.25 per share, respectively. The 2004 amount included a $171.1 million gain net of taxes associated with the sale, which netted proceeds of $583 million for the Company. All financial information has been reclassified to present the operating results for these properties as discontinued operations. The 2003 period included an after-tax expense of $7 million, $.08 per share, for a cumulative effect of a change in accounting principle associated with adoption of SFAS No. 143, Accounting for Asset Retirement Obligations. Income from continuing operations totaled $496.4 million, $5.31 per share, in 2004 compared to $278.4 million, $3.00 per share, in 2003. The $218 million improvement in income from continuing operations in 2004 was due to a combination of higher earnings from the Company’s exploration and production and refining and marketing operating businesses. Higher net costs of corporate activities partially offset the better results from these operating businesses. Exploration and production (E&P) operating results improved $208.9 million mostly due to higher oil and natural gas sales prices, higher oil sales volumes, and a $31.9 million deferred income tax benefit in Malaysia due to the expectation that temporary differences associated with exploration and other costs incurred to-date in Block K will be utilized to reduce future taxable income. The E&P results were unfavorably affected in 2004 by higher exploration expenses and lower natural gas sales volumes compared to 2003. Refining and marketing (R&M) operating results improved by $93.1 million in 2004 compared to 2003 primarily due to much stronger realized margins on petroleum products sold by the U.S. and U.K. businesses. The net costs of corporate activities were $84 million higher in 2004 because of a 5% withholding tax on a $550 million dividend to Murphy Oil Corporation from the Company’s Canadian subsidiary, unfavorable foreign exchange variances, a $20.1 million tax benefit in 2003 related to settlement of U.S. tax matters, lower capitalized interest costs due to the completion of significant E&P development projects, and higher administrative expenses related mostly to Sarbanes-Oxley compliance and retirement plans. The Canadian withholding tax in 2004 amounted to $27.5 million of costs. Foreign exchange losses were $18.6 million after tax in 2004 compared to a benefit of $5.4 million in 2003. These 2004 losses were primarily associated with U.S. dollar balances of cash and other net assets held by the Company’s Canadian and U.K. subsidiaries, which generally use local currency as their functional currency for bookkeeping purposes.
Sales and other operating revenues in 2004 increased $3.2 billion compared to 2003 mostly due to higher prices for oil, natural gas and petroleum products sold, higher sales volumes of crude oil and petroleum products, and higher merchandise sales revenue at retail gasoline stations. Gain on sale of assets increased by $8.1 million in 2004 due to a higher profit on sales of E&P properties in the year compared to 2003. Interest and other income was unfavorable by $17.5 million in 2004 versus 2003 mostly because of pretax foreign exchange losses of $26.6 million in 2004 compared to gains of $5.6 million in 2003; the foreign exchange effects were partially offset by higher interest income earned on invested cash balances during 2004. Crude oil and product purchases expense increased by $2.5 billion in 2004 due to the higher prices for crude oil purchased as refinery feedstocks and petroleum products purchased for sale at retail gasoline stations, and higher purchased volumes of crude oil, petroleum products and merchandise for resale compared to 2003. Operating expenses increased $157.3 million in 2004 with the change due to higher lifting costs caused by crude oil production growth and higher unit rates, higher refining and gasoline station expenses, and higher insurance and repair costs caused mostly by storms in the Gulf of Mexico. Exploration expenses rose by $51.6 million in 2004 mostly due to higher dry hole costs offshore Eastern Canada and in Malaysia. Selling and general expenses were $12.8 million higher in the current year and increased due to consulting fees associated with Sarbanes-Oxley compliance, plus increases for salaries, retirement and other benefits, and incentive compensation. Depreciation, depletion and amortization rose by $62.6 million mostly due to higher production of crude oil and higher depreciation of refining and marketing assets. Property impairments of $8.3 million in 2003 related to write-down of a refined products terminal closed by the company, write-off of certain property costs that were rendered obsolete at the Meraux refinery and the write-down of a natural gas field in the Gulf of Mexico due to downward revisions in reserves caused by poor well performance. Accretion of asset retirement obligations increased by $.3 million, mostly due to drilling wells and facilities added during 2004. Interest expense was $1.5 million less than in 2003 mostly due to lower average debt outstanding during 2004. Capitalized interest credited to income and included in capital expenditures decreased by $15.1 million due to completion of the Medusa development project in the Gulf of Mexico and the expansion project at the Meraux refinery. Income tax expense was $212.7 million higher in 2004 than 2003 mostly due to higher pretax income, but also because of a $20.1 million benefit in 2003 from settlement of prior year U.S. tax audits.
2003 vs. 2002– Net income in 2003 was $294.2 million, $3.17 per diluted share, compared to $111.5 million, $1.21 per diluted share, in 2002. The 2003 period included an after-tax expense of $7 million, $.08 per share, related to a cumulative effect of a change in accounting principle associated with adoption of SFAS No. 143, Accounting for Asset Retirement Obligations. The 2003 period included profit on discontinued operations of $22.8 million, $.25 per share, while the 2002 period included $24.2 million, $.26 per share. Excluding the accounting change in 2003 and the results of discontinued operations in both years, income from continuing operations was $278.4 million, $3.00 per share, in 2003, and $87.3 million, $.95 per share, in 2002. The $191.1 million higher income from continuing operations in 2003 compared to 2002 was attributable to $152.6 million higher earnings from exploration and production operations, a $28.7 million lower loss from refining and marketing operations, and $9.8 million of lower net costs from corporate activities. Earnings from exploration and production operations were up in 2003 primarily due to higher oil and natural gas sales prices, a $34 million after-tax gain on sale of the Ninian and Columba fields in the U.K. North Sea, higher oil and natural gas production, higher tax benefits from settlement and rate adjustments, and lower property impairment and exploration expenses. Refining and marketing results in both North America and the United Kingdom showed significant improvements in 2003. Most of the improvement in North America was generated by stronger margins in the retail marketing portion of the business. Higher margins in the U.K. led to better income from this area. The net costs of corporate activities were lower in 2003 primarily due to higher corporate income tax benefits related to settlement of prior year tax matters and lower net interest costs, partially offset by higher selling and general expenses.
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Sales and other operating revenues in 2003 increased by $1.3 billion compared to 2002 due to higher sales volumes for crude oil, natural gas and refined petroleum products, higher sales prices for oil, natural gas and refined products, and higher merchandise sales at retail gasoline stations. Gain on sale of assets was $52.4 million higher in 2003 primarily due to a $50 million pretax profit on sale of the Ninian and Columba fields in the U.K. North Sea. Crude oil and product purchases expense increased by $975.5 million in 2003 due to higher costs of crude oil used for refinery feedstock, and higher costs and volumes of gasoline and merchandise purchased for sale at the Company’s retail gasoline stations. Operating expenses increased by $82.4 million in 2003 due to higher operating and repair costs at refineries and higher operating costs at the Company’s growing retail gasoline station chain. Selling and general expenses rose by $27.1 million in 2003 primarily due to higher retirement and incentive compensation expenses and higher costs for Malaysian operations. Exploration expenses were $11.3 million lower in 2003 mostly due to less exploratory costs incurred in Malaysia. Depreciation, depletion and amortization expense increased by $61.3 million in 2003 due to new production from the West Patricia field, offshore Sarawak Malaysia, and higher depreciation associated with the Company’s growing retail gasoline station chain. Impairment of long-lived assets was $23.3 million lower in 2003 as the prior year included costs related to write-off of Destin Dome Blocks 56 and 57, offshore Florida. The 2003 statement of income included $9.7 million for accretion on discounted abandonment liabilities following the adoption of SFAS No. 143 on January 1, 2003. Because the abandonment liabilities are carried on the balance sheet at a discounted fair value, accretion must be recorded annually so that the liability will be recorded at full value at the time the abandonment occurs. Interest expense rose by $6.2 million in 2003 due to higher average borrowings under long-term debt during the year. The portion of interest capitalized increased by $12.7 million due to higher capital expenditures for development of deepwater Gulf of Mexico fields and expansion projects at Syncrude and the Meraux refinery. Income tax expense was $61.5 million more in 2003 mostly caused by higher pretax earnings, the effects of which were partially offset by a $20.1 million benefit from settlement of prior year tax audits in the U.S., a $10.1 million benefit related to enacted tax rate reductions in Canada, and an $11.4 million credit from recognition of deferred tax benefits in Malaysia.
In the following table, the Company’s results of operations for the three years ended December 31, 2004 are presented by segment. More detailed reviews of operating results for the Company’s exploration and production and refining and marketing activities follow the table.
(Millions of dollars) | 2004 | 2003 | 2002 | |||||||
Exploration and production | ||||||||||
United States | $ | 159.5 | 23.3 | (11.8 | ) | |||||
Canada | 232.2 | 166.2 | 146.8 | |||||||
United Kingdom | 87.1 | 95.3 | 49.6 | |||||||
Ecuador | 6.6 | 16.7 | 12.0 | |||||||
Malaysia | 38.3 | 10.7 | (43.0 | ) | ||||||
Other | (11.4 | ) | (8.8 | ) | (2.8 | ) | ||||
| 512.3 | 303.4 | 150.8 | ||||||||
Refining and marketing | ||||||||||
North America | 53.4 | (21.2 | ) | (39.2 | ) | |||||
United Kingdom | 28.5 | 10.0 | (.7 | ) | ||||||
| 81.9 | (11.2 | ) | (39.9 | ) | ||||||
Corporate and other | (97.8 | ) | (13.8 | ) | (23.6 | ) | ||||
Income from continuing operations | 496.4 | 278.4 | 87.3 | |||||||
Income from discontinued operations | 204.9 | 22.8 | 24.2 | |||||||
Income before cumulative effect of change in accounting principle | 701.3 | 301.2 | 111.5 | |||||||
Cumulative effect of change in accounting principle | — | (7.0 | ) | — | ||||||
Net income | $ | 701.3 | 294.2 | 111.5 | ||||||
Exploration and Production– Earnings from exploration and production operations were $512.3 million in 2004, $303.4 million in 2003 and $150.8 million in 2002. The increase in 2004 earnings compared to 2003 was due to a 37% higher average realized oil sales price, a 24% higher realized sales price for North American natural gas, a 17% higher sales volume of crude oil, condensate and natural gas liquids, a $31.9 million deferred income tax benefit on inception-to-date Block K exploration and other expenses, and lower impairment charges. These favorable variances more than offset lower volumes of natural gas production, higher extraction costs associated with increased oil production, higher exploration expenses caused by more dry hole costs offshore Eastern Canada and in Malaysia, higher insurance costs related to a retrospective premium adjustment on property insurance coverage and higher costs to repair damages to facilities caused by Hurricane Ivan. Higher oil production was attributable to a full year of production at Medusa and Habanero in the deepwater Gulf of Mexico and at West Patricia in Block SK 309 in Malaysia. The decline in natural gas production was due to field decline at Amethyst in the U.K. North Sea and downtime in the Gulf of Mexico for repairs for Hurricane Ivan.
The improvement in earnings in 2003 compared to 2002 was primarily caused by a 8% higher realized worldwide oil sales price, a 57% higher realized natural gas sales price in North America, record crude oil production that was 13% higher than in 2002, a 4% increase in natural gas sales volumes, a $34 million after-tax gain on sale of the Ninian and Columba fields in the U.K. North Sea, higher tax benefits from settlements
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and rate adjustments, and lower expenses related to property impairments and exploration. Higher oil production was mostly attributable to start up in May 2003 of the West Patricia field, offshore Sarawak Malaysia. The reduction in property impairment expense in 2003 was primarily related to the write-off of the remaining costs for Destin Dome Blocks 56 and 57, offshore Florida, in 2002. The decline in exploration expenses was mostly attributable to lower exploratory costs in Malaysia.
The results of operations for oil and gas producing activities for each of the last three years are shown by major operating areas on pages F-34 and F-35 of this Form 10-K report. Daily production and sales rates and weighted average sales prices are shown on page 8 of the 2004 Annual Report.
A summary of oil and gas revenues from continuing operations, including intersegment sales that are eliminated in the consolidated financial statements, is presented in the following table.
(Millions of dollars) | 2004 | 2003 | 2002 | ||||
United States | |||||||
Oil and gas liquids | $ | 248.4 | 39.2 | 30.0 | |||
Natural gas | 207.6 | 158.3 | 111.3 | ||||
Canada | |||||||
Conventional oil and gas liquids | 403.3 | 314.8 | 255.0 | ||||
Natural gas | 28.7 | 34.9 | 33.1 | ||||
Synthetic oil | 174.2 | 95.7 | 106.3 | ||||
United Kingdom | |||||||
Oil and gas liquids | 146.8 | 158.6 | 163.0 | ||||
Natural gas | 11.4 | 12.2 | 7.0 | ||||
Malaysia – crude oil | 167.2 | 77.7 | — | ||||
Ecuador – crude oil | 30.8 | 41.9 | 30.7 | ||||
Total oil and gas revenues | $ | 1,418.4 | 933.3 | 736.4 | |||
The Company’s crude oil, condensate and natural gas liquids production from continuing operations averaged 93,634 barrels per day in 2004, 76,620 barrels per day in 2003 and 67,549 barrels in 2002. Oil production in 2004 was a new annual record for Murphy Oil. The 22% increase in worldwide oil production was primarily attributable to production growth in the U.S. and Malaysia. Oil production in Canada and the U.K. declined in 2004 compared to 2003. U.S. oil production increased more than 300% to 19,314 barrels per day due to a full year of production in 2004 from the Medusa and Habanero fields. Both these fields came on stream in November 2003. Heavy oil production in Canada increased 24% to 5,838 barrels per day due to a heavy oil drilling program in the Seal area during 2004, plus additional producing acreage acquired in this area during the fourth quarter of 2004. Production at the Hibernia field off the East Coast of Canada was essentially flat with 2003 at 12,736 barrels per day, but the Terra Nova field saw production decrease 19% to 12,671 barrels per day, with the decline mostly due to mechanical problems and an oil spill that occurred during the year. Net synthetic oil production from the Syncrude project was 11,794 barrels per day, a 13% increase from 2003. The increase at Syncrude was in line with higher gross production, which was caused by better operational efficiency and less downtime in 2004 compared to 2003. Oil production in the U.K. was lower by 25% and averaged 11,011 barrels per day. The Company sold its interest in the “T” Block field in 2004 and the Ninian and Columba fields in 2003. Also, production from the Schiehallion and Mungo/Monan fields was down in 2004 due to normal decline. Production in Ecuador rose almost 50% in 2004 due to a full year of operation of the new heavy oil pipeline. In prior years, production restrictions were in effect due to limitations caused by inadequate pipeline capacity between the primary oil producing region in the country’s interior to the coast where sales occur. In spite of the higher Ecuadorian production in 2004, total sales volumes in this country in 2004 were lower than 2003 because no sales occurred from Block 16 during the second half of the year due to a dispute with the operator of the field over Murphy’s new transportation and marketing arrangements. Murphy expects to make up this sales volume shortfall of over 1.5 million barrels in 2005. Malaysian oil production rose 63% in 2004 and averaged 11,885 barrels per day, caused by a full year of production in the current year from the West Patricia field in Block SK 309 versus a partial year in 2003.
Comparing 2003 to 2002, oil production in the United States increased 10% to 4,526 barrels per day. Production from two new deepwater Gulf of Mexico fields – Medusa and Habanero – that came on stream in November 2003 more than offset production declines from mature fields. Oil production in Canada increased 11% in 2003 to 44,935 barrels per day. The 2003 production increase was primarily related to higher volumes produced offshore Newfoundland at the Terra Nova and Hibernia fields. Production at Terra Nova increased 26% and averaged 15,712 barrels per day in 2003. Hibernia production increased by 11% to 12,822 barrels per day in 2003. Net production from the synthetic oil operation known as Syncrude fell 879 barrels per day, or 8%, in 2003 due to less efficient operations caused by more downtime for repairs. Production of light oil decreased 674 barrels per day, or 54%, due to continued field decline and various property sales during the year. Heavy oil production in Canada increased 1,096 barrels per day, or 30%, during 2003 due to the results of development drilling, which was partially offset by lower production from various properties sold during the year. U.K. production was down by 3,616 barrels per day, or 20%, primarily due to sale of the Ninian and Columba fields in mid-2003 and production decline at the Mungo/Monan field. The Company produced 5,172 barrels of oil per day in
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Ecuador, 14% higher than in 2002, primarily due to a new heavy oil pipeline that began operations in the last half of 2003. Production began at the Company’s West Patricia field in Block SK 309, offshore Sarawak Malaysia, in May 2003. Net production from West Patricia averaged 7,301 barrels per day for all 2003, but averaged over 11,000 barrels per day since start-up.
Worldwide sales of natural gas from continuing operations were 109.5 million cubic feet per day in 2004, 111.8 million in 2003 and 107.7 million in 2002. Sales of natural gas in the United States were 88.6 million cubic feet per day in 2004, 82.3 million in 2003 and 88.1 million in 2002. Sales in the U.S. increased in 2004 as higher volumes produced during the full production year at the Medusa and Habanero fields in the deepwater Gulf of Mexico more than offset declines at other more mature fields. Sales volumes were unfavorably affected by Hurricane Ivan which temporarily shut in most production in the Central Gulf of Mexico and severely damaged certain facilities, such as at the Tahoe field in Viosca Knoll Block 783, which was off production for the entire fourth quarter following the storm. The reduction in 2003 U.S. sales volumes was due to lower deliverability from mature fields in the Gulf of Mexico. Natural gas sales from continuing operations in Canada fell from 19.9 million cubic feet per day in 2003 to 14 million in 2004, a reduction of 30%. The decrease was mostly caused by normal production decline at the Rimbey gas field. Canadian natural gas sales had increased in 2003 due to higher production volumes at Rimbey. Natural gas sales in the United Kingdom were down from 9.6 million cubic feet per day in 2003, to 6.9 million cubic feet in 2004. The 28% decrease in 2004 was due to normal declines at the Amethyst field in the U.K. North Sea. Natural gas sales volumes were up 37% in 2003 compared to 2002 due primarily to higher sales nominations at the Amethyst.
Worldwide crude oil sales prices have risen in each of the last two years. Oil prices rose in 2004 due to a strong world economy, real and perceived instability in worldwide crude oil production levels, and effective production output controls by OPEC producers. Murphy realized on average crude oil and condensate sales price of $35.92 per barrel in 2004, a 37% increase over the 2003 realized average price of $26.15. The worldwide average price was reduced $2.00 per barrel by the effects of the Company’s 2003 hedging program. The Company had hedged the sales price in 2003 for most of its heavy oil production in Canada and light oil production in the U.S., as well as a portion of its offshore and synthetic crude production in Canada. The average sales price in the U.S. was $35.35 per barrel in 2004, up 46%. Canadian heavy oil prices increased 64% in 2004, and averaged $20.26 per barrel. The Company’s selling price for Canadian offshore production from the Hibernia and Terra Nova fields averaged $36.60 per barrel in 2004, up 35% versus 2003. Synthetic oil production at Syncrude averaged $40.35 per barrel in 2004, 62% higher than in 2003. Murphy’s UK North Sea oil production averaged selling for $36.82 per barrel in the current year, 24% higher than 2003. Oil production sold for $24.78 per barrel in Ecuador and $41.35 per barrel in Malaysia, increases of 8% and 41%, respectively. No sales occurred from Block 16 in Ecuador during the second half of 2004 due to a dispute with the field’s operator over Murphy’s new transportation and marketing arrangements. Because of the lack of sales, the Company’s Ecuador operations did not benefit from higher average oil prices during the last six months of the just completed year. Murphy expects to make up this sales volume shortfall of over 1.5 million barrels in 2005.
The Company’s average realized sales price for crude oil and condensate in 2003 was $26.15 per barrel compared to $24.20 in 2002. The U.S. average crude oil sales price was essentially flat with 2002 and averaged $24.22 per barrel. Light oil production in Canada was sold at an average of $27.68 per barrel in 2003, up 21% from 2002. Heavy Canadian oil sold at $12.36 per barrel in 2003, 27% lower than in 2002. The average 2003 sales prices for offshore and synthetic oil production in Canada were $27.08 per barrel and $24.97 per barrel, respectively. Offshore prices were 7% higher than 2002, but synthetic crude was lower by 3%. The average sales price in the U.K. increased by 21% to $29.59 per barrel. Ecuador production was sold at an average of $22.99 per barrel, which was 17% above the average for 2002. New production from the West Patricia field in Malaysia brought an average of $29.42 per barrel in 2003.
In association with the higher oil prices, the sales prices for natural gas also strengthened in the Company’s gas producing markets during each of the past two years. The Company’s average realized sales price for North American natural gas was $6.34 per thousand cubic feet (MCF) in 2004, 24% higher than the previous year. The 2003 price was reduced by $.21 per MCF because of the Company’s hedging program in the U.S. and Canada.
In 2003, the average natural gas sales price realized by the Company in North America was $5.13 per MCF, 57% higher than in 2002. In the U.S., natural gas sales prices averaged $5.29 per MCF in 2003, up 57% compared to 2002. Canadian gas prices increased 73% to an average of $4.47 per MCF. Natural gas was sold in the U.K. at an average of $3.50 per MCF, 27% higher than the 2002 average.
Based on 2004 volumes and deducting taxes at marginal rates, each $1 per barrel and $.10 per MCF fluctuation in prices would have affected earnings from exploration and production operations by $21 million and $2.5 million, respectively. The effect of these price fluctuations on consolidated net income cannot be measured because operating results of the Company’s refining and marketing segments could be affected differently.
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Production expenses were $249 million in 2004, $189.6 million in 2003 and $189.3 million in 2002. These amounts are shown by major operating area on pages F-34 and F-35 of this Form 10-K report. Costs per equivalent barrel excluding discontinued operations during the last three years are shown in the following table.
(Dollars per equivalent barrel) | 2004 | 2003 | 2002 | ||||
United States | $ | 6.12 | 5.54 | 6.36 | |||
Canada | |||||||
Excluding synthetic oil | 3.06 | 2.64 | 4.23 | ||||
Synthetic oil | 18.05 | 16.43 | 11.75 | ||||
United Kingdom | 4.25 | 4.69 | 5.03 | ||||
Malaysia | 5.63 | 3.44 | — | ||||
Ecuador | 11.18 | 9.05 | 8.17 | ||||
Worldwide – excluding synthetic oil | 4.89 | 4.11 | 5.21 | ||||
The higher costs in the United States in 2004 were due primarily to lower production and higher costs for properties on the continental shelf of the Gulf of Mexico. The lower U.S. cost in 2003 was due to both higher production and less well servicing costs. Higher average Canadian costs excluding synthetic oil in 2004 were caused by lower natural gas production and a higher average foreign exchange rate. The decline in Canadian unit rate in 2003 was caused by a decrease in offshore costs plus the effects of higher offshore production. The increase in unit costs for Canadian synthetic oil operations in 2004 was attributable to a combination of higher maintenance and energy costs and a higher foreign exchange rate; the 2003 increase per unit was due to the same factors as 2004, plus the effects of lower barrels produced. Lower average costs in the U.K. in each of the last two years were mainly due to sale of high-cost properties, including “T” Block in 2004 and Ninian and Columba in 2003. The increase in the unit rate in Malaysia in 2004 compared to 2003 was primarily due to higher manpower, fuel and export duty costs. Production expense increases per unit in Ecuador were mostly attributable to higher transportation costs associated with the heavy oil pipeline that commenced operations in the second half of 2003.
Exploration expenses for each of the last three years are shown in total in the following table, and amounts are reported by major operating area on pages F-34 and F-35 on this Form 10-K report. Certain of the expenses are included in the capital expenditures total for exploration and production activities.
(Millions of dollars) | 2004 | 2003 | 2002 | ||||
Exploration and production | |||||||
Dry holes | $ | 110.9 | 60.6 | 89.8 | |||
Geological and geophysical | 28.4 | 31.2 | 11.3 | ||||
Other | 8.6 | 6.1 | 9.3 | ||||
| 147.9 | 97.9 | 110.4 | |||||
Undeveloped lease amortization | 16.4 | 14.7 | 13.5 | ||||
Total exploration expenses | $ | 164.3 | 112.6 | 123.9 | |||
Dry hole costs were $50.3 million higher in 2004 than 2003 because of more costs for unsuccessful drilling on the Scotian Shelf, offshore Eastern Canada, and in Block K Malaysia. Dry holes were $29.2 million lower in 2003 than 2002 primarily due to more drilling success in deepwater Malaysia blocks in the later year. Geological and geophysical expenses were $2.8 million lower in 2004, mostly due to lower seismic acquisition and interpretation work offshore Eastern Canada, partially offset by higher seismic costs in Malaysia. Geological and geophysical costs were up $19.9 million in 2003 mostly due to 3D seismic acquisition and processing in Blocks SK 309 and PM 311 in Malaysia. Other exploration expenses were $2.5 million higher in 2004 than 2003 mainly due to more costs for Gulf of Mexico annual lease rentals and higher charges for work commitments on leases on the Scotian Shelf offshore Eastern Canada. Other exploration expenses were $3.2 million lower in 2003 because more administrative costs in Malaysia were charged to the production department after start-up of West Patricia field production in May. Undeveloped leasehold amortization increased by $1.7 million in 2004 and $1.2 million in 2003 because of lease acquisitions in each year in the Gulf of Mexico, plus the acquisition in 2004 of two exploration concessions in the deep waters offshore the Republic of Congo.
Costs of $2.6 million and $5 million were incurred in 2004 and 2002, respectively, to repair equipment and well damages caused by hurricanes in the Gulf of Mexico. These costs essentially represent amounts not recovered through insurance policies. The Company’s exploration and production operations also recorded a $12.6 million pretax cost in 2004 for a retrospective insurance premium related to past claims experience of the insurer.
Depreciation, depletion and amortization expense related to exploration and production operations totaled $241.5 million in 2004, $198.6 million in 2003 and $144.7 million in 2002. The $42.9 million increase in 2004 compared to 2003 was caused primarily by higher production at the Medusa and Habanero fields in the deepwater Gulf of Mexico and the West Patricia field in Block SK 309 Malaysia. The $53.9 million increase in 2003 was mostly due to higher production in Canada and start-up of the West Patricia field in 2003.
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The exploration and production business recorded expense of $9.9 million in 2004 and $9.7 million in 2003 for accretion on discounted abandonment liabilities following the adoption of SFAS No. 143 on January 1, 2003. Because the abandonment liabilities are carried on the balance sheet at a discounted fair value, accretion must be recorded annually so that the liability will be recorded at full value at the projected time of abandonment.
Property impairments occurred in the United States in 2003 and 2002. Impairment charges of $3 million in 2003 related to the writedown of the cost of a natural gas field in the Gulf of Mexico for a reserve reduction caused by poor well performance. The impairment in 2002 of $31.6 million was mostly related to writeoff of the remaining investment of $22.5 million in Destin Dome Blocks 56 and 57, offshore Florida. Based on an agreement with the U.S. government, the Company may not seek approval for development of this significant natural gas discovery until at least 2012. The remainder of the 2002 charge also related to impairments for poor natural gas well performance in the U.S.
The effective income tax rate for exploration and production operations was 32.7% in 2004, 31.2% in 2003, and 34.8% in 2002. The effective tax rates in 2004 and 2003 were lower than statutory rates partially due to recognition of deferred income tax benefits in Malaysia in each year. The 2004 deferred tax benefit of $31.9 million arose due to the expectation that temporary differences associated with exploration and other expenses incurred to-date in Block K Malaysia will be utilized to reduce future taxable income. An $11.4 million deferred tax benefit was recognized in 2003 for similar circumstances in Malaysia Blocks SK 309 and 311. These benefits had not been recognized in the income statement in previous years because the Company had established a deferred tax valuation allowance until such time that it became probable that these expenses would be utilized as deductions to reduce future taxable income. In 2004, Alberta reduced their tax rates for oil and gas companies. In 2003, both the Federal and Alberta governments of Canada reduced their tax rates for oil and gas companies. The rate reductions led to recognition of a $4.9 million benefit in 2004 and a $10.1 million tax benefit in 2003, mostly related to a reduction in deferred income tax liabilities. In addition, the effective tax rate in 2003 was favorable to 2002 due to sale of the Company’s interests in the Ninian and Columba fields in 2003. Profits on these fields were assessed Petroleum Revenue taxes in addition to normal corporation taxes; thus the sale of these fields reduced the overall effective tax rate in the U.K.
Approximately 53% of the Company’s U.S. proved oil reserves and 38% of the U.S. proved natural gas reserves are undeveloped. At December 31, 2004, about 98% of the total U.S. undeveloped reserves (on a barrel of oil equivalent basis) are associated with deepwater Gulf of Mexico fields. Almost 70% of these undeveloped reserves relate to the Front Runner field, which came on stream in December 2004. Seven of the eight wells at Front Runner were not completed and/or producing at year-end; these wells are expected to be brought into production sequentially during 2005 and early 2006. In addition, oil reserves in Block K in Malaysia of 40 million barrels at year-end 2004 are all undeveloped, pending completion of facilities and development drilling in future years. This field is projected to be on production in the second half of 2007. On a worldwide basis, the Company spent approximately $272 million in 2004, $280 million in 2003, and $239 million in 2002 to develop proved reserves. The Company expects to spend about $307 million in 2005, $558 million in 2006 and $422 million in 2007 to move currently undeveloped proved reserves to the developed category.
Refining and Marketing– The Company’s refining and marketing operations generated a profit of $81.9 million in 2004, after posting losses of $11.2 million in 2003 and $39.9 million in 2002. The R&M operating results improved markedly in 2004 because the Company was able to extract a higher gross margin from product sales in both the U.S. and U.K. markets. Although the price of crude oil, the primary refinery feedstock, was much more costly during 2004 than in 2003, the supplies of gasoline and certain other products remained tight during much of the year. Thus refining margins in both the U.S. and U.K. were much stronger during 2004. The Meraux refinery also ran more efficiently in 2004 than in 2003, and therefore, the costs of operations were spread over a larger number of crude oil barrels, benefiting margins on a per-unit basis. Murphy also enjoyed better profits from its Murphy USA retail station chain in 2004, essentially due to a combination of higher volumes sold, a better markup of gasoline prices compared to laid-in costs, and lower operating costs per gallon sold. The Company added 129 stations to its chain during 2004, an increase of 21% over the number of sites at year-end 2003. Sales volume per station increased more than 6% in 2004 compared to 2003.
The 2003 loss from R&M operations was lower than the 2002 loss by $28.7 million primarily due to better margins from the gasoline retail business in North America and the refining and marketing business in the United Kingdom. The Company’s U.S. refining margins were squeezed in 2003, primarily due to the high price of crude oil that the Company was not able to completely pass through to wholesale and other refinery customers. In addition to higher average fuel margins in 2003 at North American retail gasoline stations, the Company’s profits from merchandise sales at these gasoline stations were also better than in 2002.
Geographically, the North American R&M operations had income of $53.4 million in 2004 after incurring losses of $21.2 million in 2003 and $39.2 million in 2002. North American operations include refining activities in the United States and marketing activities in the United States and Canada. Operations in the U.K. generated a record profit of $28.5 million in 2004, compared to a profit of $10 million in 2003 and a $.7 million loss in 2002.
Unit margins (sales realizations less costs of crude oil and other feedstocks, refinery operating and depreciation expenses and transportation to point of sale) averaged $2.25 per barrel in North America in 2004, $1.60 in 2003 and $.80 in 2002. North American product sales volumes increased 31% to a record 301,801 barrels per day in 2004, following a 30% increase in 2003. Sales volumes through the Company’s retail gasoline network at Wal-Mart stores grew steadily throughout 2004 and 2003.
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Unit margins in the United Kingdom averaged $4.85 per barrel in 2004, $2.86 per barrel in 2003 and $1.70 per barrel in 2002. Sales of petroleum products were up 6% in 2004 following a 2% increase in 2003. The 2004 increase was primarily caused by higher volumes sold in both the retail and cargo market, while the increase in 2003 was mostly attributable to cargo market sales growth.
U.S. refining and marketing operations were experiencing losses in early 2005 as this business was unable at that time to pass along the higher costs of crude oil feedstocks to its customers buying refined products such as gasoline and diesel.
Based on sales volumes for 2004 and deducting taxes at marginal rates, each $.42 per barrel ($.01 per gallon) fluctuation in the unit margins would have affected annual refining and marketing profits by $32.7 million. The effect of these unit margin fluctuations on consolidated net income cannot be measured because operating results of the Company’s exploration and production segments could be affected differently.
Corporate– The costs of corporate activities, which include interest income, interest expense, foreign exchange gains and losses, and corporate overhead not allocated to operating functions, were $97.8 million in 2004, $13.8 million in 2003 and $23.6 million in 2002. Net after-tax corporate costs in 2004 were $84 million higher than in 2003. The increase was related to unfavorable foreign exchange losses, higher administrative costs, higher net interest expense and unfavorable income taxes. Due to a much weaker U.S. dollar compared to the Canadian dollar, pound sterling and the Euro, the Company incurred after-tax losses of $18.6 million for foreign exchange in 2004 compared to a $5.4 million profit in 2003. The exchange losses were mostly attributable to foreign subsidiaries with non-U.S. dollar functional currencies holding a significant level of U.S. dollars that experienced devaluation against these other currencies during the last half of 2004. Administrative expenses were $8.5 million higher in 2004, mostly due to higher costs of corporate compliance under the Sarbanes-Oxley Act and higher salaries, retirement and other benefits and other compensation expenses. Net interest expense was $13.5 million higher in 2004, mostly due to lower interest being capitalized on U.S. oil and gas developments and U.S. refinery expansion projects that are now completed and the assets in service. Income tax expense in 2004 was unfavorable by $43 million in the corporate area primarily due to a $27.5 million withholding tax incurred on a $550 million dividend paid to the Company by its Canadian subsidiary, and a $20.1 million tax benefit in 2003 from settlement of previous years’ income tax audit issues. The Company earned $13.3 million more interest income in 2004 mostly related to holding larger balances of invested cash for a portion of the year after selling most of its conventional oil and gas properties in Western Canada.
Net after-tax corporate costs were $9.8 million lower in 2003 than in 2002 mainly due to a $20.1 million benefit from settlement of previous years’ U.S. income tax audit issues and lower net interest expense. These cost savings were partially offset by higher general and administrative expenses, including costs related to the Company’s retirement and incentive compensation plans.
Capital Expenditures
As shown in the selected financial data on page 8 of this Form 10-K report, capital expenditures for continuing operations, including discretionary exploration expenditures, were $975.4 million in 2004 compared to $906.1 million in 2003 and $774.8 million in 2002. These amounts included $147.9 million, $97.9 million and $110.4 million of exploration costs that were expensed. Capital expenditures for exploration and production activities totaled $839.2 million in 2004, 86% of the Company’s total capital expenditures for the year. Exploration and production capital expenditures in 2004 included $16.6 million for acquisition of undeveloped leases, $54 million and $67.3 million for acquisition of unproved and proved properties, respectively, in the Seal area in Western Canada, $268.1 million for exploration activities, and $433.2 million for development projects. Development expenditures included $86.3 million for development of deepwater discoveries in the Gulf of Mexico; $104.6 million for the West Patricia and Kikeh fields in Malaysia; $33.7 million for the Terra Nova and Hibernia oil fields, offshore Newfoundland; $99.6 million for expansion of synthetic oil operations at the Syncrude project in Canada; and $68.1 million for Western Canada heavy oil and natural gas projects. Exploration and production capital expenditures are shown by major operating area on page F-33 of this Form 10-K report.
Refining and marketing capital expenditures totaled $134.7 million in 2004, compared to $215.4 million in 2003 and $234.7 million in 2002. These amounts represented 14%, 24% and 30% of capital expenditures for continuing operations of the Company in 2004, 2003 and 2002, respectively. Refining capital spending was $46.1 million in 2004 compared to $130.8 million in 2003 and $150.1 million in 2002. In 2004, the Company completed the construction of a green gasoline unit at its Superior, Wisconsin refinery. In 2003, it finished the expansion of the Meraux, Louisiana refinery, which included building a hydrocracker unit to meet future clean fuel specifications and expanding the crude oil processing capacity of the plant to 125,000 barrels per day. Capital expenditures on the Superior refinery unit green gasoline were $18 million in 2004 and $5.5 million in 2003. Capital expenditures related to the Meraux expansion project amounted to $5.5 million in 2004, $69 million in 2003 and $116.2 million in 2002. Marketing expenditures amounted to $88.6 million in 2004 and $84.6 million in 2003 and 2002. The majority of marketing expenditures in each year was related to construction of retail gasoline stations at Wal-Mart sites in 21 states in the U.S. The Company added 129 total stations to this retail network in 2004, 119 in 2003 and 125 in 2002.
Cash Flows
Cash provided by continuing operations was $1,035.1 million in 2004, $501.1 million in 2003 and $372.2 million in 2002. The increase in cash provided in 2004 was primarily due to higher crude oil and refined product sales volumes, and higher sales prices for crude oil, natural gas and refined products. Cash provided by continuing operations was reduced by expenditures for refinery turnarounds and abandonment of oil and gas properties totaling $18.6 million in 2004, $66.1 million in 2003 and $14.8 million in 2002. Scheduled plant-wide turnarounds occurred at both U.S. refineries in 2003.
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Cash proceeds from property sales other than from discontinued operations were $60.4 million in 2004, $188.6 million in 2003 and $68.1 million in 2002. The 2004 property sales included the disposal of the “T” Block field in the U.K. North Sea and certain U.S. onshore gas properties and U.S. marketing terminals while 2003 included disposal of the Ninian and Columba fields in the U.K. and various oil and gas assets in Canada and the Gulf of Mexico. Disposals of properties classified as discontinued operations brought in net cash proceeds of $583 million in 2004. This disposal included most of the Company’s conventional oil and gas properties in Western Canada. During 2003 and 2002, the Company borrowed under notes payable and other long-term debt arrangements primarily to fund a portion of the Company’s development capital expenditures; these borrowings provided $309.7 million of cash in 2003 and $407.6 million in 2002. Cash proceeds from stock option exercises and employee stock purchase plans amounted to $3.2 million in 2004, $3.6 million in 2003 and $25.1 million in 2002.
Property additions and dry hole costs used cash of $938.4 million in 2004, $868.9 million in 2003 and $765.9 million in 2002. A heavy oil property acquisition in Canada, plus higher heavy oil development spending and higher exploration drilling in Malaysia were the primary reasons for the increase in 2004. More field development expenditures in the deepwater Gulf of Mexico and at the West Patricia and Kikeh fields in Malaysia mostly accounted for the 2003 increase. The Company used a portion of the proceeds of asset dispositions classified as discontinued operations to repay a significant portion of long-term debt in 2004. Total paydown of debt was $495 million during 2004. Cash outlays for debt repayment during 2003 and 2002 were $76.8 million and $57.8 million, respectively. Cash of $17.9 million was invested in 2004 in U.S. government securities with maturities greater than 90 days. Cash used for dividends to stockholders was $78.2 million in 2004, $73.5 million in 2003 and $70.9 million in 2002. The Company raised its annualized dividend rate from $.80 per share to $.90 per share beginning in the third quarter of 2004. The Company had previously increased the annualized dividend rate from $.75 per share to $.80 per share at mid-year 2002.
Financial Condition
Year-end working capital totaled $424.4 million in 2004, $228.5 million in 2003 and $136.3 million in 2002. The current level of working capital does not fully reflect the Company’s liquidity position as the carrying values for inventories under last-in first-out accounting were $219.1 million below fair value at December 31, 2004. Cash and cash equivalents at the end of 2004 totaled $535.5 million compared to $252.4 million a year ago and $165 million at the end of 2002.
Long-term debt was reduced by $477 million during 2004 and totaled $613.3 million at the end of the year, 18.8% of total capital employed. Long-term debt included $15.6 million of nonrecourse debt incurred in connection with the Hibernia oil field. The long-term debt reduction in 2004 was achieved primarily using the proceeds of asset dispositions in Western Canada. Long-term debt totaled $1.09 billion at the end of 2003 compared to $862.8 million at December 31, 2002. Stockholders’ equity was $2.65 billion at the end of 2004 compared to $1.95 billion a year ago and $1.59 billion at the end of 2002. A summary of transactions in stockholders’ equity accounts is presented on page F-6 of this Form 10-K report.
Other significant changes in Murphy’s year-end 2004 balance sheet compared to 2003 included a $252.7 million increase in accounts receivable, which was primarily caused by sales of higher volumes of crude oil and refined products at higher average prices near the end of 2004 compared to the 2003 year-end. Crude oil and blend stocks inventory was $24.4 million more than 2003 mostly because of 1.5 million barrels of unsold crude oil inventory in Ecuador. The Company did not receive its allocated share of Ecuadorian production to sell for approximately the last seven months of 2004 due to a dispute with the area operator over our new transportation and marketing arrangements. Short-term deferred income tax assets increased $10.5 million at year-end 2004 due mostly to a deferred tax benefit recorded in 2004 in Ecuador; this benefit offset a current tax charge related to a temporary difference associated with the timing of income reported for book and tax purposes. Net property, plant and equipment increased by $154.8 million as capital expenditures during the year were larger than the cost of properties disposed and the additional depreciation and amortization expensed. Goodwill related to the acquisition of Beau Canada in 2000 decreased by $21.3 million as a portion of goodwill was allocated to the cost pool for the sale of Western Canada properties in 2004. Deferred charges and other assets increased $21.6 million in 2004 due to the net change in long-term deferred tax assets for Malaysian operations. Current maturities of long-term debt declined by $16.5 million primarily because of paydown of Hibernia nonrecourse loans. Accounts payable rose by $237.7 million mostly due to the higher costs of purchased crude oil and gasoline at year-end 2004 compared to 2003. Income taxes payable increased $158.4 million at year-end 2004 due to combination of higher operating profits in 2004 and a liability associated with settlement of all Beau Canada Exploration acquisition financing matters with the Canadian tax authorities during early 2005. Other taxes payable increased $27.2 million mostly due to higher sales, use and excise taxes owed at year-end 2004 compared to 2003. Deferred income tax liabilities increased $155.3 million in 2004 due mostly to higher accelerated depreciation taken in tax returns based on 2004 property acquisitions and other capital expenditures. The liability associated with asset retirements dropped by $50.5 million mostly due to sales of Western Canada conventional oil and gas properties and “T” Block in the North Sea during 2004. Accrued major repair costs increased by $23.7 million primarily based on accruing additional costs for future turnarounds of the company���s three refineries.
Murphy had commitments of $727 million for capital projects in progress at December 31, 2004, including $28 million for costs to develop deepwater Gulf of Mexico fields, $63 million for continued expansion of synthetic oil operations in Canada, $394 million for field development and future work commitments in Malaysia, and $37 million for exploration drilling in Congo.
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The primary sources of the Company’s liquidity are internally generated funds, access to outside financing and working capital. The Company typically relies on internally generated funds to finance the major portion of its capital and other expenditures, but maintains lines of credit with banks and borrows as necessary to meet spending requirements. At December 31, 2004, the Company had access to short-term and long-term revolving credit facilities in the amount of $700 million. None of the revolving facilities had been drawn at year-end 2004. The most restrictive covenants under these facilities limit the Company’s long-term debt to capital ratio (as defined in the agreements) to 60%. At December 31, 2004, the long-term debt to capital ratio was approximately 19%. The Company also has unused uncommitted credit lines of approximately $392 million at December 31, 2004. In addition, the Company has a shelf registration on file with the U.S. Securities and Exchange Commission that permits the offer and sale of up to $650 million in debt and equity securities. Current financing arrangements are set forth more fully in Note E to the consolidated financial statements. At present, the Company does not anticipate utilizing a significant amount of its long-term borrowing capacity in 2005 as normal cash flow from operations is expected to cover the Company’s capital expenditure program. At March 1, 2005 the Company’s long-term debt rating by Standard and Poor’s was “A-” and by Moody’s was “Baal”. The Company’s ratio of earnings to fixed charges was 13.4 to 1 in 2004, 6.1 to 1 in 2003 and 2.7 to 1 in 2002.
Environmental
Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations. The most significant of those laws and the corresponding regulations affecting the Company’s operations are:
| • | The Clean Air Act, as amended |
| • | The Federal Water Pollution Control Act |
| • | Safe Drinking Water Act |
| • | Regulations of the United States Department of the Interior governing offshore oil and gas operations |
These acts and their associated regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. Many states also have similar statutes and regulations governing air and water, which in some cases impose additional and more stringent requirements. Murphy is also subject to certain acts and regulations primarily governing remediation of wastes or oil spills. The applicable acts are:
| • | The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), commonly referred to as Superfund, and comparable state statutes. CERCLA primarily addresses historic contamination and imposes joint and several liability for cleanup of contaminated sites on owners and operators of the sites. As discussed below, Murphy is involved in a limited number of Superfund sites. CERCLA also requires reporting of releases to the environment of substances defined as hazardous. |
| • | The Resource Conservation and Recovery Act of 1976, as amended, and comparable state statutes, govern the management and disposal of wastes, with the most stringent regulations applicable to treatment, storage or disposal of hazardous wastes at the owner’s property. |
| • | The Oil Pollution Act of 1990, as amended, under which owners and operators of tankers, owners and operators of onshore facilities and pipelines, and lessees or permittees of an area in which an offshore facility is located are liable for removal and cleanup costs of oil discharges into navigable waters of the United States. Pursuant to the authority of the Clean Air Act (CAA), the Environmental Protection Agency (EPA) has issued several standards applicable to the formulation of motor fuels, which are designed to reduce emissions of certain air pollutants when the fuel enters commerce or is used. Pursuant to state laws corresponding to the CAA, several states have passed similar or more stringent regulations governing the formulation of motor fuels. |
The Company is also involved in personal injury and property damage claims, allegedly caused by exposure to or by the release or disposal of materials manufactured or used in the Company’s operations.
The Company operates or has previously operated certain sites and facilities, including three refineries, five terminals, and approximately 80 service stations, for which known or potential obligations for environmental remediation exist. In addition the Company operates or has operated numerous oil and gas fields that may require some form of remediation.
Under the Company’s accounting policies, an environmental liability is recorded when such an obligation is probable and the cost can be reasonably estimated. If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used. Recorded liabilities are reviewed quarterly. Actual cash expenditures often occur one or more years after a liability is recognized.
The Company’s liability for remedial obligations includes certain amounts that are based on anticipated regulatory approval for proposed remediation of former refinery waste sites. Although regulatory authorities may require more costly alternatives than the proposed processes, the cost of such potential alternative processes is not expected to exceed the accrued liability by a material amount.
The U.S. Environmental Protection Agency (EPA) currently considers the Company to be a Potentially Responsible Party (PRP) at two Superfund sites. The potential total cost to all parties to perform necessary remedial work at these sites may be substantial. Based on currently available
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information, the Company believes that it is a de minimus party as to ultimate responsibility at both Superfund sites. The Company has not recorded a liability for remedial costs on Superfund sites. The Company could be required to bear a pro rata share of costs attributable to nonparticipating PRPs or could be assigned additional responsibility for remediation at the two sites or other Superfund sites. The Company believes that its share of the ultimate costs to clean-up the two Superfund sites will be immaterial and will not have a material adverse effect on its net income, financial condition or liquidity in a future period.
There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on net income, financial condition or liquidity in a future period.
Certain environmental expenditures are likely to be recovered by the Company from other sources, primarily environmental funds maintained by certain states. Since no assurance can be given that future recoveries from other sources will occur, the Company has not recorded a benefit for likely recoveries at December 31, 2004.
The Company’s refineries also incur costs to handle and dispose of hazardous waste and other chemical substances. The types of waste and substances disposed of generally fall into the following categories: spent catalysts (usually hydrotreating catalysts); spent/used filter media; tank bottoms and API separator sludge; contaminated soils; laboratory and maintenance spent solvents; and various industrial debris. The costs of disposing of these substances are expensed as incurred and amounted to $6.6 million in 2004. In addition to these expenses, Murphy allocates a portion of its capital expenditure program to comply with environmental laws and regulations. Such capital expenditures were approximately $60.3 million in 2004 and are projected to be $35.9 million in 2005.
Other Matters
Impact of inflation –General inflation was moderate during the last three years in most countries where the Company operates; however, the Company’s revenues and capital and operating costs are influenced to a larger extent by specific price changes in the oil and gas and allied industries than by changes in general inflation. Crude oil and petroleum product prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC production levels and/or attitudes of traders concerning supply and demand in the near future. Natural gas prices are affected by supply and demand, which to a significant extent are affected by the weather and by the fact that delivery of gas is generally restricted to specific geographic areas. Because crude oil and natural gas sales prices have generally strengthened during the last two years, prices for oil field goods and services could be adversely affected in the future. Due to the volatility of oil and natural gas prices, it is not possible to determine what effect these prices will have on the future cost of oil field goods and services.
Accounting changes and recent accounting pronouncements– As described in Note G on page F-14 of this Form 10-K report, Murphy adopted the Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standards (SFAS) 143, Accounting for Asset Retirement Obligations, effective January 1, 2003. Upon adoption of SFAS No. 143, the Company recorded an after-tax charge of $7 million, which was reported as the cumulative effect of a change in accounting principle.
The Financial Accounting Standards Board (FASB) has issued Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), Share Based Payment, which replaces SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. SFAS No. 123 (revised 2004) requires that the cost resulting from all share-based payment transactions be recognized as an expense in the financial statements using a fair-value-based measurement method over the periods that the awards vest. The statement will be effective for the Company beginning in its third quarter which starts on July 1, 2005. The Company is currently evaluating which fair value measurement method to use and whether to use the modified retrospective application or modified prospective application upon adoption. Although the Company currently uses the intrinsic-value approach of Accounting Principles Board No. 25 to account for stock options, it provides pro forma disclosures in Note A as if SFAS No. 123 was currently being applied.
The FASB has issued for comment a proposed FASB Staff Position (FSP) 19-a to provide guidance on the accounting for exploratory well costs and to propose an amendment to SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies. The guidance in FSP 19-a will apply to companies that use the successful efforts method of accounting as described in SFAS No. 19. This proposed FSP would clarify that exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating validity of the project. The guidance in this FSP is to be applied in the first reporting period beginning after the date the FSP is finalized. The guidance will be applied prospectively to existing and newly-capitalized exploratory well costs. However, any capitalized well costs that do not meet the requirements of the FSP must be written off upon its adoption. The proposed FSP as written requires additional disclosures related to capitalized costs.
The Emerging Issues Task Force (EITF) has issued EITF 03-13, Applying the Conditions in Paragraph 42 of SFAS No. 144 in Determining Whether to Report Discontinued Operations. The EITF generally believes that current practice with respect to applying the criteria in paragraph 42 of
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SFAS No. 144 has not been applied consistently and has not resulted in broadening the reporting of asset dispositions as discontinued operations. EITF 03-13 contains further guidance for evaluating the cash flows of the component sold and what constitutes significant continuing involvement. This standard must be applied to all asset disposal transactions occurring after January 1, 2005. EITF 03-13 may lead in certain industries to more asset disposals being reported as discontinued operations in future periods. However, in the oil and gas industry, it may cause more asset disposals to continue to be classified as continuing operations due to clarification of what constitutes continuing involvement.
In October 2004, the President of the United States signed into law the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (the “Act”). The FASB issued FSP 109-1 in December 2004 to provide guidance on the application of SFAS No. 109, Accounting for Income Taxes, to the provision within the Act that provides, beginning in 2005, a tax deduction of up to 9% on qualified production activities. FSP 109-1 concludes that the deduction should be accounted for as a special deduction in accordance with SFAS 109, which means that the tax benefit is recognized as realized, rather than as a one-time benefit due to a reduction of deferred tax liabilities. This FSP was effective upon issuance. The Company cannot predict what impact the Act will have on net income in future periods.
SFAS No. 151, Inventory Costs was issued by the FASB in November 2004. This statement amends Accounting Research Bulletin No. 43, to clarify that abnormal amounts of idle facility expense, freight, handling costs, and wasted materials should be recognized as current-period charges, and it also requires that allocation of fixed production overheads be based on the normal capacity of the related production facilities. The provisions of this statement will be effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The provisions of this statement will be applied prospectively. The Company does not expect the adoption of this statement to have a significant impact on its results of operations.
The FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets an amendment of APB Opinion No. 29, in December 2004. This statement addresses the measurement of exchanges of nonmonetary assets and eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. The provisions of SFAS No. 153 will be effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The provisions of this statement will be applied prospectively. The Company does not expect the adoption of this statement to have a significant impact on its results of operations.
In 2004 the FASB reviewed whether mineral interests in properties (mineral leases) held by oil and gas companies should be recorded and disclosed as intangible assets under the guidance of SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. After consideration of the matter, the FASB issued a staff position stating that drilling and mineral rights of oil and gas producing entities that are within the scope of SFAS 19 are not subject to the intangible asset classification and disclosure rules of SFAS No. 142. The staff position is consistent with the Company’s present accounting practices and had no effect on its financial statements or disclosures.
Significant accounting policies– In preparing the Company’s financial statements in accordance with accounting principles generally accepted in the United States, management must make a number of estimates and assumptions related to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Application of certain of the Company’s accounting policies requires significant estimates. The most significant of these accounting policies are described below.
| • | Proved oil and natural gas reserves – Proved reserves are defined by the U.S. Securities and Exchange Commission (SEC) 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. Although the Company’s engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. SEC rules require that year-end oil and natural gas prices must be used for determining proved reserve quantities. Year-end prices often do not approximate the average price that the Company expects to receive for its oil and natural gas production. The Company often uses significantly different oil and natural gas assumptions when making its own internal economic property evaluations. Estimated reserves are often subject to future revision, certain of which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and natural gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to adjustments of the Company’s depreciation rates and the timing of settlement of asset retirement obligations. The Company’s proved reserves of oil and natural gas are presented on pages F-31 and F-32 of the annual report. The reserve revision for U.S. oil in 2004 relates primarily to loss of royalty relief for the Medusa and Front Runner deepwater fields based on year-end 2004 oil prices. Oil reserve revisions in Canada in 2004 relate to a combination of low heavy oil prices at year-end that restrict economic recoverability of certain heavy oil reserves and higher projected royalties at the Terra Nova and Hibernia fields. Oil reserve revisions in Ecuador in 2004 were caused by a higher than previously estimated water cut in the liquid stream produced at Block 16. Natural gas reserve revisions were positive in the U.S. due to better well performance. The Company cannot predict the type of reserve revisions that will be required in future periods. |
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| • | Successful efforts accounting – The Company utilizes the successful efforts method to account for exploration and development expenditures. Unsuccessful exploration wells are expensed and can have a significant effect on net income. Successful exploration drilling costs, all development capital expenditures and asset retirement costs are capitalized and systematically charged to expense using the units of production method based on proved oil and natural gas reserves as estimated by the Company’s engineers. |
In some cases, a determination of whether a drilled well has found proved reserves can not be made immediately. This is generally due to the need for a major capital expenditure to produce and/or evacuate the hydrocarbon(s) found. The determination of whether to make such a capital expenditure is, in turn, usually dependent on whether additional exploratory wells find a sufficient quantity of additional reserves. When further drilling is firmly planned or in progress, the Company holds these well costs in Property, Plant and Equipment until the drilling is completed. In cases where oil and gas reserves have been found but can not be classified as proved within one year after an exploratory well is drilled, the Company will hold such well costs in Property when classification of proved reserves are dependent upon, and we are actively seeking, approval of a development plan by a foreign government.
Costs of all exploration wells in progress at year-end 2004 amounted to $29 million. Through early March 2005, these wells were either still drilling or successfully found hydrocarbon deposits, certain of which are still being evaluated by the Company.
Based on the time required to complete further exploration and appraisal drilling in areas where hydrocarbons have been found but proved reserves have not been booked, dry hole expense may be recorded one or more years after the original drilling costs are incurred. Dry hole expenses related to wells drilled in prior years were $13.2 million in 2004 and $10.7 million in 2002.
| • | Impairment of long-lived assets – The Company continually monitors its long-lived assets recorded in Property, Plant and Equipment and Goodwill in the Consolidated Balance Sheets to make sure that they are fairly presented. The Company must evaluate its properties for potential impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. Goodwill must be evaluated for impairment at least annually. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the amount of oil and natural gas that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, future capital and abandonment costs, and future inflation levels. The need to test a property for impairment can be based on several factors, including but not limited to a significant reduction in sales prices for oil and/or natural gas, unfavorable reserve revisions, or other changes to contracts, environmental regulations or tax laws. All of these same factors must be considered when testing a property’s carrying value for impairment. A description of impairment charges recorded during the last three years is included in Note D in the consolidated financial statements. |
In making its impairment assessments involving exploration and production property and equipment, the Company must make a number of projections involving future oil and natural gas sales prices, future production volumes, and future capital and operating costs. Due to the volatility of world oil and gas markets, the actual sales prices for oil and natural gas have often been quite different from the Company’s projections. Estimates of future oil and gas production and sales volumes are based on a combination of proved and risked probable and possible reserves. Although the estimation of reserves and future production is uncertain, the Company believes that its estimates are reasonable; however, there have been cases where actual production volumes were higher or lower than projected and the timing was different than the original projection. The Company adjusts reserve and production estimates as new information becomes available. The Company generally projects future costs by using historical costs adjusted for both assumed long-term inflation rates and known or expected changes in future operations. Although the projected future costs are considered to be reasonable, at times, costs have been higher or lower than originally estimated. In making impairment assessments for refining and marketing property and equipment, future margins for the refining and marketing business are generally projected based on historical results adjusted for known or expected changes in future operations. Although the Company is not aware of any property carrying values that are impaired at December 31, 2004, one or a combination of factors such as significantly lower future sales prices, significantly lower future production, significantly higher future costs, or significantly lower future margins for refining and marketing, could lead to impairment expenses in future periods. Based on these unknown future factors as described herein, the Company can not predict the amount or timing of impairment expenses that may be recorded in the future.
| • | Income taxes – The Company is subject to income and other similar taxes in all areas in which it operates. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of its annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; and (c) future events often impact the timing of when income tax expenses and benefits are recognized by the Company. The Company has deferred tax assets mostly relating to property basis differences and liabilities for repairs, dismantlements and retirement benefits. The Company routinely evaluates all deferred tax assets to determine the likelihood of their realization. A valuation allowance has been recognized for deferred tax assets related to basis differences for Blocks H and PM 311/312 in Malaysia and certain basis differences in the U.K. due to management’s belief that these assets cannot be deemed to be realizable with any degree of confidence at this time. The Company occasionally is challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions in its various income tax returns. Although the Company believes that it has adequate accruals for matters not resolved with various taxing authorities, gains or losses could occur in future years from changes in estimates or resolution of outstanding matters. |
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| • | Legal, environmental and other contingent matters – A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and other contingent matters. In addition, the Company often must estimate the amount of such losses. In many cases, management’s judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. The Company’s management closely monitors known and potential legal, environmental and other contingent matters, and makes its best estimate of the amount of losses and when they should be recorded based on information available to the Company. |
Contractual obligations and guarantees– The Company is obligated to make future cash payments under borrowing arrangements, operating leases, purchase obligations and other long-term liabilities. In addition, the Company expects to extend certain operating losses beyond the minimum contractual period. Total payments due after 2004 under such contractual obligations and arrangements are shown below.
| Amount of Obligation | |||||||||||
(Millions of dollars) | Total | 2005 | 2006-2008 | 2009-2010 | After 2010 | ||||||
Total debt including current maturities | $ | 664,082 | 50,727 | 13,037 | 2,622 | 597,696 | |||||
Operating leases | 202,734 | 19,967 | 50,531 | 25,810 | 106,426 | ||||||
Purchase obligations | 946,609 | 751,730 | 66,716 | 31,453 | 96,710 | ||||||
Other long-term liabilities | 309,489 | 31,482 | 20,873 | 13,228 | 243,906 | ||||||
Total | $ | 2,122,914 | 853,906 | 151,157 | 73,113 | 1,044,738 | |||||
In addition to the obligations as of December 31, 2004 as reflected in the above table, in early 2005 the Company entered into a floating, production, storage and offloading (FPSO) vessel lease and a dry tree unit construction contract associated with development of the Kikeh field in Block K Malaysia. Total Kikeh field development costs are expected to be $1.9 billion.
In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide financial guarantees or letters of credit that may be drawn upon if the Company fails to perform under those contracts. The amount of commitments as of December 31, 2004 that expire in future periods is shown below.
| Amount of Commitment | |||||||||||
(Millions of dollars) | Total | 2005 | 2006- 2008 | 2009- 2010 | After 2010 | ||||||
Financial guarantees | $ | 8,519 | — | 2,593 | — | 5,926 | |||||
Letters of credit | 55,979 | 35,414 | 20,565 | — | — | ||||||
Total | $ | 64,498 | 35,414 | 23,158 | — | 5,926 | |||||
Material off-balance sheet arrangements– The Company occasionally utilizes off-balance sheet arrangements for operational or funding purposes. The most significant of these arrangements at year-end 2004 involve an oil and natural gas processing contract and a hydrogen purchase contract. The processing contract provides crude oil and natural gas processing capacity for oil and natural gas production from the Medusa field in the Gulf of Mexico. Under the contract, the Company pays a specified amount per barrel of oil equivalent for processing its oil and natural gas through the facility. If actual oil and natural gas production processed through the facility through 2009 is less than a specified quantity, the Company must make additional quarterly payments up to an agreed minimum level that varies over time. The Company has a contract to purchase hydrogen for the Meraux refinery through 2019. The contract requires a monthly minimum base facility charge whether or not any hydrogen is purchased. Payments under both these agreements are recorded as operating expenses when paid. Future required minimum annual payments under both of these arrangements are included in the contractual obligation table shown above.
Outlook
Prices for the Company’s primary products are often quite volatile. A strong global economy, political uncertainty in Iraq and the Middle East, and effective price management practices utilized by OPEC led to high oil prices during 2004 and early 2005. Natural gas prices also were strong in 2004 and early 2005, mainly due to the high price of crude oil and also because demand for the product often outstrips supply in the short term. Due to the volatility of worldwide crude oil prices and North American natural gas prices routine monitoring of spending plans is required.
The Company’s capital expenditure budget for 2005 was prepared during the fall of 2004 and provides for capital expenditures of $1.066 billion. Of this amount, $887 million or 83%, is allocated for exploration and production. Geographically, 19% of the exploration and production budget is allocated to the United States, including $57 million for development of deepwater projects in the Gulf of Mexico; another 24% is allocated to Canada, including $68 million for development of heavy oil fields and $78 million for further expansion of synthetic oil operations; 49% is allocated to exploration and development in Malaysia, including $141 million for field development at Kikeh in Block K; and the remaining 8% is planned for other areas, including Ecuador, the United Kingdom and the Republic of Congo. Budgeted refining and marketing capital expenditures for 2005 are $171 million, including $146 million in North America and $25 million in the United Kingdom. Planned spending in North America includes funds to build 150 additional gasoline stations at Wal-Mart sites. Capital and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and actual cash flow during 2005.
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The Company currently does not anticipate a significant increase in long-term borrowings during 2005. Although Murphy’s 2005 Budget includes a robust amount of capital spending, the Company expects normal operating cash flows to be sufficient to cover planned spending. It is possible that long-term debt could increase significantly in 2005, especially if cash flows are adversely affected in the near term by significantly weaker oil and natural gas sales prices and continued weak refining and marketing margins such as those experienced in early 2005. Rising crude prices in early 2005 squeezed refining and marketing margins; this business was experiencing losses in early 2005.
The Company has made a significant oil discovery in Block K offshore Sabah, Malaysia at a field named Kikeh. A field development plan, as approved by the Company’s Board of Directors and the Malaysian authorities, calls for gross development costs of $1.9 billion, which includes $.5 billion of lease costs for an FPSO. The Company has an 80% working interest in the field. It is likely that a significant portion of the Company’s share of funding for field development in 2006 will come from borrowed capital. First production from the Kikeh field offshore Sabah is estimated to occur in the second half of 2007.
Murphy’s oil and natural gas production is expected to grow in 2005. Production from the Front Runner deepwater Gulf of Mexico field will ramp up in 2005 and development drilling in Western Canada at Seal should lead to higher heavy oil production. The combination of higher Front Runner and Seal production is expected to more than offset normal production declines elsewhere. Total production for 2005 is projected to average approximately 130,000 barrels of oil equivalent per day.
Murphy Oil and certain of its subsidiaries maintain defined benefit retirement plans covering most of its full-time employees. Due to a reduction in bond yields during 2004, the Company has reduced the primary plans’ discount rate from 6.25% in 2004 to 6.00% in 2005. Although the Company presently assumes a return on plan assets of 7.5% for the primary plan, it periodically reconsiders the appropriateness of this and other key assumptions. The smoothing effect of current accounting regulations tend to buffer the current year’s pension expense from wide swings in liabilities and asset returns. The effect of a lower discount rate and a growing employee population will lead to higher pension expense in 2005. The Company’s annual retirement plan expense is estimated to increase by about $1.4 million for 2005 compared to 2004. In 2005, the Company is expecting to fund payments of approximately $12.1 million into various retirement plans and $2.9 million for postretirement plans. The Company could be required to make additional and more significant funding payments to retirement plans in future years.
Forward-Looking Statements
This Form 10-K report, including documents incorporated by reference here, contains statements of the Company’s expectations, intentions, plans and beliefs that are forward-looking and are dependent on certain events, risks and uncertainties that may be outside of the Company’s control. These forward-looking statements are made in reliance upon the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Actual results and developments could differ materially from those expressed or implied by such statements due to a number of factors including those described in the context of such forward-looking statements as well as those contained in the Company’s January 15, 1997 Form 8-K report on file with the U.S. Securities and Exchange Commission.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note A to the consolidated financial statements, Murphy makes limited use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.
Murphy was a party to natural gas price swap agreements at December 31, 2004 for a remaining notional volume of 2.2 million MMBTU that are intended to hedge the financial exposure of its Meraux, Louisiana refinery to fluctuations in the future price of a portion of natural gas to be purchased for fuel in 2005 and 2006. In each month of settlement, the swaps require Murphy to pay an average natural gas price of $3.35 per MMBTU and to receive the average NYMEX price for the final three trading days of the month. At December 31, 2004, the estimated fair value of these agreements was recorded as an asset of $6.1 million. A 10% increase in the average NYMEX price of natural gas would have increased this asset by $1.3 million, while a 10% decrease would have reduced the asset by a similar amount.
At December 31, 2004, the Company was a party to forward sale contracts covering 2,000 barrels per day in heavy oil sales during 2005 and 4,000 barrels per day in 2006. The contracts are intended to hedge the financial exposure of the Company’s heavy oil sales in Canada during the respective contract period and are priced at $29.00 per barrel in 2005 and $25.23 per barrel in 2006. At December 31, 2004, the estimated fair value of these agreements was recorded as an asset valued at $.6 million. A 10% increase in the price of Canadian heavy oil at the Hardisty terminal in Canada would have decreased this asset by $5.6 million, while a 10% decrease would have increased this asset by a similar amount.
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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Information required by this item appears on pages F-1 through F-38, which follow page 29 of this Form 10-K report.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
Item 9A. CONTROLS AND PROCEDURES
Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by Murphy to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.
Based on the Company’s evaluation as of the end of the period covered by the filing of this Annual Report on Form 10-K, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
Murphy’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control – Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2004. Our report is included on F-2 of the annual report. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included on page F-2 of this annual report.
There were no significant changes in the Company’s internal controls over financial reporting that occurred during the fourth quarter of 2004 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
None
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Certain information regarding executive officers of the Company is included on page 7 of this Form 10-K report. Other information required by this item is incorporated by reference to the Registrant’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 11, 2005 under the caption “Election of Directors.”
Murphy Oil has adopted a Code of Ethical Conduct for Executive Management, which can be found under the Corporate Governance and Responsibility tab at www.murphyoilcorp.com. Stockholders may also obtain free of charge a copy of the Code of Ethical Conduct for Executive Management by writing to the Company’s Secretary at P.O. Box 7000, El Dorado, AR 71731-7000. Any future amendments to or waivers of the Company’s Code of Ethical Conduct for Executive Management will be posted on the Company’s internet website.
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Item 11. EXECUTIVE COMPENSATION
Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 11, 2005 under the captions “Compensation of Directors,” “Executive Compensation,” “Option Exercises and Fiscal Year-End Values,” “Option Grants,” “Compensation Committee Report for 2004,” “Shareholder Return Performance Presentation” and “Retirement Plans.”
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 11, 2005 under the captions “Security Ownership of Certain Beneficial Owners,” “Security Ownership of Management,” and “Equity Compensation Plan Information.”
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None
Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 11, 2005 under the caption “Audit Committee Report.”
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
| Page No. | ||
| F-1 | ||
| F-1 | ||
Report of Management – Internal Control Over Financial Reporting | F-2 | |
| F-2 | ||
| F-3 | ||
| F-4 | ||
| F-5 | ||
| F-6 | ||
| F-7 | ||
| F-8 | ||
| F-30 | ||
| F-38 |
2. Financial Statement Schedules
| F-39 |
| All other 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.
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| Exhibit No. | Incorporated by Reference to | |||
| 3.1 | Certificate of Incorporation of Murphy Oil Corporation as amended, effective May 17, 2001 | Exhibit 3.1 of Murphy’s Form 10-Q report for the quarterly period ended June 30, 2001 | ||
| 3.2 | By-Laws of Murphy Oil Corporation as amended effective February 2, 2005 | Exhibit 3.2 of Murphy’s Form 8-K report filed February 4, 2005 under the Securities Exchange Act of 1934 | ||
| 4 | Instruments Defining the Rights of Security Holders. Murphy is party to several long-term debt instruments in addition to those in Exhibit 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 | Form of Second Supplemental Indenture between Murphy Oil Corporation and SunTrust Bank, as Trustee | Exhibit 4.1 of Murphy’s Form 8-K report filed May 3, 2002 under the Securities Exchange Act of 1934 | ||
| *4.2 | Form of Indenture and Form of Supplemental Indenture between Murphy Oil Corporation and SunTrust Bank, as Trustee | |||
| *4.3 | Rights Agreement dated as of December 6, 1989 between Murphy Oil Corporation and Harris Trust Company of New York, as Rights Agent | |||
| *4.4 | Amendment No. 1 dated as of April 6, 1998 to Rights Agreement dated as of December 6, 1989 between Murphy Oil Corporation and Harris Trust Company of New York, as Rights Agent | |||
| *4.5 | Amendment No. 2 dated as of April 15, 1999 to Rights Agreement dated as of December 6, 1989 between Murphy Oil Corporation and Harris Trust Company of New York, as Rights Agent | |||
| 10.1 | 1992 Stock Incentive Plan as amended May 14, 1997, December 1, 1999 and May 14, 2003 | Exhibit 10.1 of Murphy’s Form 10-Q report for the quarterly period ended June 30, 2003 | ||
| 10.2 | 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 | ||
| 10.3 | Murphy Vehicle Fueling Station Master Ground Lease Agreement | Exhibit 10.3 of Murphy’s Form 10-K report for the year ended December 31, 2002 | ||
| 10.4 | Stock Plan for Non-Employee Directors, as approved by shareholders on May 14, 2003 | Exhibit 10.4 of Murphy’s Form 10-K report for the year ended December 31, 2003 | ||
| *10.5a | Floating, Production, Storage and Offloading vessel charter contract for Kikeh field | |||
| *10.5b | Floating, Production, Storage and Offloading vessel operating and maintenance agreement for Kikeh field | |||
| *10.6 | Dry Tree Unit contract for Kikeh field | |||
| *12.1 | Computation of Ratio of Earnings to Fixed Charges | |||
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| Exhibit No. | Incorporated by Reference to | |||
| *13 | 2004 Annual Report to Security Holders | |||
| *21 | Subsidiaries of the Registrant | |||
| *23 | Consent of Independent Registered Public Accounting Firm | |||
| *31.1 | Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |||
| *31.2 | Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |||
| 32 | Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | See footnote 1 below. | ||
| *99.1 | Form of employee stock option | |||
| *99.2 | Form of employee restricted stock award | |||
| *99.3 | Form of non-employee director stock option | |||
| *99.4 | Form of non-employee director restricted stock award | |||
| 1 | These certifications will not be deemed to be filed with the Commission or incorporated by reference into any filing by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates such certifications by reference. |
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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 15, 2005 | ||
| Claiborne P. Deming, President | ||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 15, 2005 by the following persons on behalf of the registrant and in the capacities indicated.
/s/ WILLIAM C. NOLAN JR. | /s/ IVAR B. RAMBERG | |
| William C. Nolan Jr., Chairman and Director | Ivar B. Ramberg, Director |
/s/ CLAIBORNE P. DEMING | /s/ NEAL E. SCHMALE | |
Claiborne P. Deming, President and Chief Executive Officer and Director (Principal Executive Officer) | Neal E. Schmale, Director |
/s/ FRANK W. BLUE | /s/ DAVID J. H. SMITH | |
| Frank W. Blue, Director | David J. H. Smith, Director |
/s/ GEORGE S. DEMBROSKI | /s/ CAROLINE G. THEUS | |
| George S. Dembroski, Director | Caroline G. Theus, Director |
/s/ ROBERT A. HERMES | /s/ STEVEN A. COSSÉ | |
| Robert A. Hermes, Director | Steven A. Cossé, Executive Vice President and General Counsel (Principal Financial Officer) |
/s/ R. MADISON MURPHY | /s/ JOHN W. ECKART | |
| R. Madison Murphy, Director | John W. Eckart, Controller (Principal Accounting Officer) |
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REPORT OF MANAGEMENT – CONSOLIDATED FINANCIAL STATEMENTS
The management of Murphy Oil Corporation is responsible for the preparation and integrity of the accompanying consolidated financial statements and other financial data. The statements were prepared in conformity with generally accepted U.S. accounting principles appropriate in the circumstances and include some amounts based on informed estimates and judgments, with consideration given to materiality.
An independent registered public accounting firm, KPMG LLP, has audited the Company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board and provides an objective, independent opinion about the fair presentation of the consolidated financial statements. The Board of Directors appoints the independent auditors; ratification of the appointment is solicited annually from the shareholders.
The Board of Directors appoints an Audit Committee annually to implement and to support the Board’s oversight function of the Company’s financial reporting, accounting policies, internal controls and independent registered public accounting firm. This Committee is composed solely of directors who are not employees of the Company. The Committee meets routinely with representatives of management, the Company’s audit staff and the independent registered public accounting firm to review and discuss the adequacy and effectiveness of the Company’s internal controls, the quality and clarity of its financial reporting, the scope and results of independent and internal audits, and to fulfill other responsibilities included in the Committee’s Charter. The independent registered public accounting firm and the Company’s audit staff have unrestricted access to the Committee, without management presence, to discuss audit findings and other financial matters.
Our report of management covering internal control over financial reporting and the associated report of independent registered public accounting firm can be found at F-2.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of Murphy Oil Corporation:
We have audited the accompanying consolidated balance sheets of Murphy Oil Corporation and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2004. In connection with our audits of the consolidated financial statements we also have audited financial statement Schedule II. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the Standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Murphy Oil Corporation and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
As discussed in Note G to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Murphy Oil Corporation’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 14, 2005 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
KPMG LLP
Houston, Texas
March 14, 2005
F-1
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REPORT OF MANAGEMENT – INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control – Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2004. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included herein.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of Murphy Oil Corporation:
We have audited management’s assessment, included in the accompanying Report of Management – Internal Control Over Financial Reporting, that Murphy Oil Corporation maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Murphy Oil Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that Murphy Oil Corporation maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Murphy Oil Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Murphy Oil Corporation and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2004, and our report dated March 14, 2005, expressed an unqualified opinion on those consolidated financial statements.
KPMG LLP
Houston, Texas
March 14, 2005
F-2
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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31 (Thousands of dollars except per share amounts) | 2004 | 2003* | 2002* | |||||||
Revenues | ||||||||||
Sales and other operating revenues | $ | 8,299,147 | 5,094,518 | 3,779,381 | ||||||
Gain on sale of assets | 69,594 | 61,524 | 9,148 | |||||||
Interest and other income (loss) | (8,902 | ) | 8,615 | 8,388 | ||||||
Total revenues | 8,359,839 | 5,164,657 | 3,796,917 | |||||||
Costs and Expenses | ||||||||||
Crude oil and product purchases | 6,153,413 | 3,678,729 | 2,703,185 | |||||||
Operating expenses | 739,407 | 582,131 | 499,698 | |||||||
Exploration expenses, including undeveloped lease amortization | 164,227 | 112,638 | 123,920 | |||||||
Selling and general expenses | 132,329 | 119,538 | 92,403 | |||||||
Depreciation, depletion and amortization | 321,446 | 258,857 | 197,537 | |||||||
Impairment of long-lived assets | — | 8,314 | 31,640 | |||||||
Accretion of asset retirement obligations | 10,017 | 9,734 | — | |||||||
Interest expense | 56,224 | 57,751 | 51,504 | |||||||
Interest capitalized | (22,160 | ) | (37,240 | ) | (24,536 | ) | ||||
Total costs and expenses | 7,554,903 | 4,790,452 | 3,675,351 | |||||||
Income from continuing operations before income taxes | 804,936 | 374,205 | 121,566 | |||||||
Income tax expense | 308,541 | 95,795 | 34,287 | |||||||
Income from continuing operations | 496,395 | 278,410 | 87,279 | |||||||
Income from discontinued operations, net of tax | 204,920 | 22,780 | 24,229 | |||||||
Income before cumulative effect of change in accounting principle | 701,315 | 301,190 | 111,508 | |||||||
Cumulative effect of change in accounting principle, net of tax | — | (6,993 | ) | — | ||||||
Net Income | $ | 701,315 | 294,197 | 111,508 | ||||||
Income per Common Share – Basic | ||||||||||
Income from continuing operations | $ | 5.39 | 3.03 | .96 | ||||||
Income from discontinued operations | 2.23 | .25 | .26 | |||||||
Cumulative effect of change in accounting principle | — | (.08 | ) | — | ||||||
Net Income – Basic | $ | 7.62 | 3.20 | 1.22 | ||||||
Income per Common Share – Diluted | ||||||||||
Income from continuing operations | $ | 5.31 | 3.00 | .95 | ||||||
Income from discontinued operations | 2.20 | .25 | .26 | |||||||
Cumulative effect of change in accounting principle | — | (.08 | ) | — | ||||||
Net Income – Diluted | $ | 7.51 | 3.17 | 1.21 | ||||||
Average Common shares outstanding – basic | 91,986,321 | 91,814,821 | 91,450,836 | |||||||
Average Common shares outstanding – diluted | 93,443,511 | 92,742,766 | 92,134,967 | |||||||
| * | Reclassified to conform to 2004 presentation. |
See notes to consolidated financial statements, page F-8.
F-3
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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31 (Thousands of dollars) | 2004 | 2003 | |||||
Assets | |||||||
Current assets | |||||||
Cash and cash equivalents | $ | 535,525 | 252,425 | ||||
Short-term investments in marketable securities | 17,892 | — | |||||
Accounts receivable, less allowance for doubtful accounts of $13,962 in 2004 and $14,328 in 2003 | 702,933 | 450,201 | |||||
Inventories, at lower of cost or market | |||||||
Crude oil and blend stocks | 71,010 | 46,626 | |||||
Finished products | 155,295 | 157,078 | |||||
Materials and supplies | 69,540 | 66,806 | |||||
Prepaid expenses | 45,771 | 44,779 | |||||
Deferred income taxes | 31,397 | 20,940 | |||||
Total current assets | 1,629,363 | 1,038,855 | |||||
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $2,933,214 in 2004 and $3,472,133 in 2003 | 3,685,594 | 3,530,800 | |||||
Goodwill, net | 43,582 | 64,873 | |||||
Deferred charges and other assets | 99,704 | 78,119 | |||||
Total assets | $ | 5,458,243 | 4,712,647 | ||||
Liabilities and Stockholders’ Equity | |||||||
Current liabilities | |||||||
Current maturities of long-term debt | $ | 50,727 | 67,224 | ||||
Accounts payable | 709,378 | 471,692 | |||||
Income taxes | 241,935 | 83,493 | |||||
Other taxes payable | 147,459 | 120,258 | |||||
Other accrued liabilities | 55,492 | 67,659 | |||||
Total current liabilities | 1,204,991 | 810,326 | |||||
Notes payable | 597,735 | 1,061,410 | |||||
Nonrecourse debt of a subsidiary | 15,620 | 28,897 | |||||
Deferred income taxes | 577,043 | 421,700 | |||||
Asset retirement obligations | 201,932 | 252,397 | |||||
Accrued major repair costs | 44,246 | 20,513 | |||||
Deferred credits and other liabilities | 167,520 | 166,521 | |||||
Stockholders’ equity | |||||||
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued | — | — | |||||
Common Stock, par $1.00, authorized 200,000,000 shares at December 31, 2004 and 2003, issued 94,613,379 shares | 94,613 | 94,613 | |||||
Capital in excess of par value | 511,045 | 504,809 | |||||
Retained earnings | 1,981,020 | 1,357,910 | |||||
Accumulated other comprehensive income | 134,509 | 65,246 | |||||
Unamortized restricted stock awards | (4,738 | ) | — | ||||
Treasury stock | (67,293 | ) | (71,695 | ) | |||
Total stockholders’ equity | 2,649,156 | 1,950,883 | |||||
Total liabilities and stockholders’ equity | $ | 5,458,243 | 4,712,647 | ||||
See notes to consolidated financial statements, page F-8.
F-4
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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31 (Thousands of dollars) | 2004 | 2003* | 2002* | |||||||
Operating Activities | ||||||||||
Income from continuing operations | $ | 496,395 | 278,410 | 87,279 | ||||||
Adjustments to reconcile income from continuing operations to net cash provided by operating activities | ||||||||||
Depreciation, depletion and amortization | 321,446 | 258,857 | 197,537 | |||||||
Impairment of long-lived assets | — | 8,314 | 31,640 | |||||||
Provisions for major repairs | 30,208 | 28,514 | 24,996 | |||||||
Expenditures for major repairs and asset retirements | (18,587 | ) | (66,096 | ) | (14,839 | ) | ||||
Dry hole costs | 110,866 | 60,674 | 89,770 | |||||||
Amortization of undeveloped leases | 16,415 | 14,720 | 13,546 | |||||||
Accretion of asset retirement obligations | 10,017 | 9,734 | — | |||||||
Deferred and noncurrent income tax charges | 106,159 | 4,237 | 2,675 | |||||||
Pretax gains from disposition of assets | (69,594 | ) | (61,524 | ) | (9,148 | ) | ||||
Net increase in noncash operating working capital | (20,053 | ) | (37,285 | ) | (40,895 | ) | ||||
Other operating activities – net | 51,785 | 2,572 | (10,356 | ) | ||||||
Net cash provided by continuing operations | 1,035,057 | 501,127 | 372,205 | |||||||
Net cash provided by discontinued operations | 61,961 | 151,151 | 160,639 | |||||||
Net cash provided by operating activities | 1,097,018 | 652,278 | 532,844 | |||||||
Investing Activities | ||||||||||
Property additions and dry hole costs | (938,449 | ) | (868,870 | ) | (765,856 | ) | ||||
Proceeds from sale of property, plant and equipment | 60,404 | 188,620 | 68,056 | |||||||
Purchase of investment securities | (17,892 | ) | — | — | ||||||
Other investing activities – net | (840 | ) | 1,309 | (2,177 | ) | |||||
Investing activities of discontinued operations | ||||||||||
Sales proceeds | 582,973 | — | 7,182 | |||||||
Other | (9,730 | ) | (68,906 | ) | (68,651 | ) | ||||
Net cash required by investing activities | (323,534 | ) | (747,847 | ) | (761,446 | ) | ||||
Financing Activities | ||||||||||
Additions to notes payable | — | 309,500 | 407,053 | |||||||
Reductions of notes payable | (454,178 | ) | (34,912 | ) | (32,457 | ) | ||||
Additions to nonrecourse debt of a subsidiary | 30 | 188 | 573 | |||||||
Reductions of nonrecourse debt of a subsidiary | (40,829 | ) | (41,844 | ) | (25,354 | ) | ||||
Proceeds from exercise of stock options and employee stock purchase plans | 3,156 | 3,598 | 25,131 | |||||||
Cash dividends paid | (78,205 | ) | (73,464 | ) | (70,898 | ) | ||||
Other financing activities – net | — | (1,533 | ) | (2,778 | ) | |||||
Net cash provided (required) by financing activities | (570,026 | ) | 161,533 | 301,270 | ||||||
Effect of exchange rate changes on cash and cash equivalents | 79,642 | 21,504 | 9,637 | |||||||
Net increase in cash and cash equivalents | 283,100 | 87,468 | 82,305 | |||||||
Cash and cash equivalents at January 1 | 252,425 | 164,957 | 82,652 | |||||||
Cash and cash equivalents at December 31 | $ | 535,525 | 252,425 | 164,957 | ||||||
| * | Reclassified to conform to 2004 presentation. |
See notes to consolidated financial statements, page F-8.
F-5
Table of Contents
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
Years Ended December 31 (Thousands of dollars) | 2004 | 2003 | 2002 | |||||||
Cumulative Preferred Stock - par $100, authorized 400,000 shares, none issued | — | — | — | |||||||
Common Stock - par $1.00, authorized 200,000,000 shares, issued 94,613,379 shares at December 31, 2004, 2003 and 2002 and 48,775,314 shares at beginning of 2002 | ||||||||||
Balance at beginning of year | $ | 94,613 | 94,613 | 48,775 | ||||||
Two-for-one stock split on December 30, 2002 | — | — | 45,838 | |||||||
Balance at end of year | 94,613 | 94,613 | 94,613 | |||||||
Capital in Excess of Par Value | ||||||||||
Balance at beginning of year | 504,809 | 504,983 | 527,126 | |||||||
Exercise of stock options, including income tax benefits | 738 | 729 | 20,039 | |||||||
Restricted stock transactions and other | 4,610 | (1,472 | ) | 2,563 | ||||||
Sale of stock under employee stock purchase plans | 888 | 569 | 1,093 | |||||||
Two-for-one stock split on December 30, 2002 | — | — | (45,838 | ) | ||||||
Balance at end of year | 511,045 | 504,809 | 504,983 | |||||||
Retained Earnings | ||||||||||
Balance at beginning of year | 1,357,910 | 1,137,177 | 1,096,567 | |||||||
Net income for the year | 701,315 | 294,197 | 111,508 | |||||||
Cash dividends - $.85 per share in 2004, $.80 per share in 2003 and $.775 per share in 2002 | (78,205 | ) | (73,464 | ) | (70,898 | ) | ||||
Balance at end of year | 1,981,020 | 1,357,910 | 1,137,177 | |||||||
Accumulated Other Comprehensive Income (Loss) | ||||||||||
Balance at beginning of year | 65,246 | (66,790 | ) | (83,309 | ) | |||||
Foreign currency translation gains, net of income taxes | 79,073 | 145,573 | 30,878 | |||||||
Cash flow hedging gains (losses), net of income taxes | (4,876 | ) | 17,912 | (13,007 | ) | |||||
Minimum pension liability adjustment, net of income taxes | (4,934 | ) | (31,449 | ) | (1,352 | ) | ||||
Balance at end of year | 134,509 | 65,246 | (66,790 | ) | ||||||
Unamortized Restricted Stock Awards | ||||||||||
Balance at beginning of year | — | — | (968 | ) | ||||||
Stock awards | (4,756 | ) | — | — | ||||||
Amortization, forfeitures and changes in price of Common Stock | 18 | — | 968 | |||||||
Balance at end of year | (4,738 | ) | — | — | ||||||
Treasury Stock | ||||||||||
Balance at beginning of year | (71,695 | ) | (76,430 | ) | (90,028 | ) | ||||
Exercise of stock options | 1,568 | 2,261 | 12,852 | |||||||
Sale of stock under employee stock purchase plans | 617 | 799 | 749 | |||||||
Awarded restricted stock, net of forfeitures | 2,217 | 1,675 | (3 | ) | ||||||
Balance at end of year - 2,578,002 shares of Common Stock in 2004, 2,742,781 shares in 2003 and 2,923,925 shares in 2002 | (67,293 | ) | (71,695 | ) | (76,430 | ) | ||||
Total Stockholders’ Equity | $ | 2,649,156 | 1,950,883 | 1,593,553 | ||||||
See notes to consolidated financial statements, page F-8.
F-6
Table of Contents
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Years Ended December 31 (Thousands of dollars) | 2004 | 2003 | 2002 | |||||||
Net income | $ | 701,315 | 294,197 | 111,508 | ||||||
Other comprehensive income (loss), net of tax | ||||||||||
Cash flow hedges | ||||||||||
Net derivative gains (losses) | 8,022 | (27,702 | ) | (8,065 | ) | |||||
Reclassification to income | (12,898 | ) | 45,614 | (4,942 | ) | |||||
Total cash flow hedges | (4,876 | ) | 17,912 | (13,007 | ) | |||||
Net gain from foreign currency translation, net of tax | 79,073 | 145,573 | 30,878 | |||||||
Minimum pension liability adjustment, net of tax | (4,934 | ) | (31,449 | ) | (1,352 | ) | ||||
Other comprehensive income | 69,263 | 132,036 | 16,519 | |||||||
Comprehensive Income | $ | 770,578 | 426,233 | 128,027 | ||||||
See notes to consolidated financial statements, page F-8.
F-7
Table of Contents
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, Malaysia and Ecuador and conducts oil and natural gas exploration activities worldwide. The Company has an interest in a Canadian synthetic oil operation, owns two petroleum refineries in the United States and has an interest in a refinery in the United Kingdom. Murphy markets petroleum products under various brand names and to unbranded wholesale customers in North America 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 from sales of crude oil, natural gas and refined petroleum products are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer. Title transfers for crude oil, natural gas and bulk refined products generally occur at pipeline custody points or when a tanker lifting has occurred. Refined products sold at retail are recorded when the customer takes delivery at the pump. Revenues from the production of oil and natural gas properties in which Murphy shares an undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period. Gas imbalances occur when the Company’s actual sales differ from its entitlement under existing working interests. The Company records a liability for gas imbalances when it has sold more than its working interest of gas production and the estimated remaining reserves make it doubtful that partners can recoup their share of production from the field. At December 31, 2004 and 2003, the liabilities for natural gas balancing 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.
The Company enters into buy/sell and similar arrangements when crude oil and other petroleum products are held at one location but are needed at a different location. The Company often pays or receives funds related to the buy/sell arrangement based on location or quality differences. The Company accounts for such transactions on a net basis in its consolidated statement of income. The Financial Accounting Standards Board’s Emerging Issues Task Force (EITF) is reviewing the accounting treatment for buy/sell and similar arrangements. Although the EITF has not yet completed its review, we do not expect to have any significant accounting changes based on this review.
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.
MARKETABLE SECURITIES – The Company classifies its investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities”. The Company does not have any investments classified as trading. Available-for-sale securities are carried at fair value with the unrealized gain or loss, net of tax, reported in other comprehensive income. Held-to-maturity securities are recorded at amortized cost. Premiums and discounts are amortized or accreted into earnings over the life of the related available-for-sale or held-to-maturity security. Dividend and interest income is recognized when earned. Unrealized losses considered to be “other than temporary” are recognized currently in earnings. The cost of securities sold is based on the specific identification method. The fair value of investment securities is determined by available market prices. The Company’s short-term investments in marketable securities at December 31, 2004 are classified as held-to-maturity and the contractual maturity is due within one year.
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. Costs of undeveloped leases are generally expensed over the life of the leases. In certain cases, a determination of whether a drilled exploration well has found proved reserves can not be made immediately. This is generally due to the need for a major capital expenditure to produce and/or evacuate the hydrocarbon(s) found. The determination of whether to make such a capital expenditure is, in turn, usually dependent on whether additional exploratory wells find a sufficient quantity of additional reserves. When further drilling is firmly planned or in progress, the Company holds these well costs in Property, Plant and Equipment until the drilling is completed. In addition, cases where oil and gas reserves have been found but can not be classified as proved within one year after an exploratory well is drilled, the Company will hold such well costs in Property, Plant and Equipment when classification of proved reserves are dependent upon, and we are actively seeking, approval of a development plan by a foreign government. The Company reevaluates its capitalized drilling costs at least annually to ascertain whether drilling costs continue to qualify for ongoing capitalization. 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 for impairment 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.
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Depreciation and depletion of producing oil and gas properties is recorded based on units of production. Unit rates are computed for unamortized exploration drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. As more fully described on page F-30 of this Form 10-K report, proved reserves are estimated by the Company’s engineers and are subject to future revisions based on availability of additional information. As described in Note G, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 143 on January 1, 2003. Under SFAS No. 143, estimated asset retirement costs are generally recognized when the asset is placed in service, and are amortized over proved reserves using the units of production method. Prior to adoption of SFAS No. 143, estimated dismantlement, abandonment and site restoration costs, net of salvage value, were generally recognized using the units of production method and were included in depreciation expense. Asset retirement costs are estimated by the Company’s engineers using existing regulatory requirements and anticipated future inflation rates. Refineries and certain marketing facilities are depreciated primarily using the composite straight-line method with depreciable lives ranging from 16 to 25 years. Gasoline stations and other properties are depreciated over 3 to 20 years by individual unit on the straight-line method.
Gains and losses on asset disposals or retirements are included in income. Actual costs of asset retirements such as dismantling oil and gas production facilities and site restoration are charged against the related liability. See also Note G for further discussion.
Full plant turnarounds for major processing units are scheduled at 4-1/2 year intervals at the Meraux, Louisiana refinery and five year intervals at the Superior, Wisconsin refinery. Turnarounds at the Milford Haven, Wales refinery are scheduled on a four year cycle. Turnarounds for coking units at Syncrude Canada Ltd. are scheduled at intervals of two to three years. Turnaround work associated with various other less significant units at the Company’s refineries and Syncrude will occur during the interim period and will vary depending on operating requirements and events. Murphy accrues in advance for estimated costs of these turnarounds by recording monthly expense provisions. Future major repair costs are estimated by the Company’s engineers. Actual costs incurred are charged against the accrued liability. Once the turnaround is completed and actual costs are reasonably known, variances between accrued and actual costs are recorded in Operating Expenses in the income statement in the current period. All other maintenance and repairs are expensed. Renewals and betterments are capitalized.
INVENTORIES – Unsold crude oil production is carried in inventory at the lower of cost, generally applied on a first-in first-out (FIFO) basis, or market. Refinery inventories of crude oil and other feedstocks and finished product inventories 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) in 2000 was recorded as goodwill. All goodwill recorded at December 31, 2004 and 2003 arose from the purchase of Beau Canada by the Company’s wholly owned Canadian subsidiary. In accordance with SFAS No. 142, Goodwill and Other Intangible Assets, goodwill is not amortized. SFAS No. 142 requires an annual assessment of recoverability of the carrying value of goodwill. The Company assesses goodwill recoverability at each year-end by comparing the fair value of net assets for conventional oil and natural gas properties in Canada with the carrying value of these net assets including goodwill. The fair value of the conventional oil and natural gas reporting unit is determined using the expected present value of future cash flows. The carrying amount of goodwill at December 31, 2004 and 2003 was $43,582,000 and $64,873,000, respectively. The decrease in the carrying amount of goodwill during 2004 was primarily due to the allocation of $23,091,000 of goodwill to the cost basis of Canadian conventional oil and gas assets that the Company sold during the second quarter 2004, and the remainder of the difference was caused by a change in the foreign currency translation rate between year-end 2004 and 2003. Based on its assessment of the fair value of its Canadian conventional oil and natural gas operations, the Company believes the recorded value of goodwill is not impaired at December 31, 2004. Should a future assessment indicate that goodwill is not fully recoverable, an impairment charge to write down the carrying value of goodwill would be required.
ENVIRONMENTAL LIABILITIES – A provision for environmental obligations is charged to expense when a liability for an environmental assessment and/or cleanup is probable and the cost can be reasonably estimated. Related expenditures are charged against the liability. 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 for refining and marketing activities in the United Kingdom. The U.S. dollar is the functional currency used to record all other operations. Gains or losses from translating foreign functional currency into U.S. dollars are included in Accumulated Other Comprehensive Income on the Consolidated Balance Sheets. Exchange gains or losses from transactions in a currency other than the functional currency are included in income.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES – The Company accounts for derivative instruments and hedging activity under SFAS No. 133, as amended by SFAS No. 138 and No. 149. The fair value of a derivative instrument is recognized as an asset or liability in the
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Company’s Consolidated Balance Sheet. Upon entering into a derivative contract, the Company may designate the derivative as either a fair value hedge or a cash flow hedge, or decide that the contract is not a hedge, and thenceforth, mark the contract to fair value through earnings. The Company documents the relationship between the derivative instrument designated as a hedge and the hedged items as well as its objective for risk management and strategy for use of the hedging instrument to manage the risk. Derivative instruments designated as fair value or cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions. The Company assesses at inception and on an ongoing basis whether a derivative instrument used as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting. Changes in the fair value of a qualifying fair value hedge are recorded in earnings along with the gain or loss on the hedged item. Changes in the fair value of a qualifying cash flow hedge are recorded in other comprehensive income until earnings are affected by the cash flows of the hedged item. When the cash flow of the hedged item is recognized in the Statement of Income, the fair value of the associated cash flow hedge is reclassified from other comprehensive income into earnings. Ineffective portions of a cash flow hedging derivative’s change in fair value are recognized currently in earnings. If a derivative instrument no longer qualifies as a cash flow hedge, hedge accounting is discontinued and the gain or loss recorded in other comprehensive income is recognized immediately in earnings.
STOCK OPTIONS – Through 2004, the Company used the intrinsic-value based method of accounting as prescribed by Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees and related interpretations to account for its stock options. Under this method, the Company accrues costs of restricted stock and any stock option deemed to be variable in nature over the vesting/performance period and adjusts such costs for changes in the fair market value of Common Stock. No compensation expense is recorded for fixed stock options since all option prices have been equal to or greater than the fair market value of the Company’s stock on the date of grant. As more fully described in Note B, SFAS No. 123 (revised 2004), Share-Based Payments, will require the Company to expense the fair value of stock-based compensation, including stock options, beginning on July 1, 2005. Had the Company recorded compensation expense for stock options as prescribed by the previously issued SFAS No. 123, Accounting for Stock-Based Compensation, net income and earnings per share would be the pro forma amounts shown in the following table.
(Thousands of dollars except per share data) | 2004 | 2003 | 2002 | |||||||
Net income – As reported | $ | 701,315 | 294,197 | 111,508 | ||||||
Restricted stock compensation expense included in income, net of tax | 1,353 | 197 | 2,295 | |||||||
Total stock-based compensation expense using fair value method for all awards, net of tax | (6,199 | ) | (5,442 | ) | (9,611 | ) | ||||
Net income – Pro forma | $ | 696,469 | 288,952 | 104,192 | ||||||
Net income per share – As reported, basic | $ | 7.62 | 3.20 | 1.22 | ||||||
Pro forma, basic | 7.57 | 3.15 | 1.14 | |||||||
As reported, diluted | 7.51 | 3.17 | 1.21 | |||||||
Pro forma, diluted | 7.45 | 3.11 | 1.13 | |||||||
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 accounting principles generally accepted in the United States of America, 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 and Recent Accounting Pronouncements
The Financial Accounting Standards Board (FASB) has issued Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), Share Based Payment, which replaces SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. SFAS No. 123 (revised 2004) requires that the cost resulting from all share-based payment transactions be recognized as an expense in the financial statements using a fair-value-based measurement method over the periods that the awards vest. The statement will be effective for the Company beginning in its third quarter which starts on July 1, 2005. The Company is currently evaluating which fair value measurement method to use and whether to use the modified retrospective application or modified prospective application upon adoption. The Company provides pro forma disclosures in Note A as if SFAS No. 123 was currently being applied.
The EITF has issued EITF 03-13, Applying the Conditions in Paragraph 42 of SFAS No. 144 in Determining Whether to Report Discontinued Operations. The EITF generally believes that current practice with respect to applying the criteria in paragraph 42 of SFAS No. 144 has not been applied consistently and has not resulted in broadening the reporting of asset dispositions as discontinued operations. EITF 03-13 contains further guidance for evaluating the cash flows of the component sold and what constitutes significant continuing involvement. This standard must be applied to all asset disposal transactions occurring after January 1, 2005. In certain industries, EITF 03-13 may lead to more asset disposals being reported as discontinued operations in future periods. However, in the oil and gas industry, it may cause more asset disposals to continue to be classified as continuing operations due to clarification of what constitutes continuing involvement.
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In October 2004, the President of the United States signed into law the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (the “Act”). The FASB issued FSP 109-1 in December 2004 to provide guidance on the application of SFAS No. 109, Accounting for Income Taxes, to the provision within the Act that provides, beginning in 2005, a tax deduction of up to 9% on qualified production activities. The tax deduction phases in at 3% in 2005 and reaches 9% in 2010. FSP 109-1 concluded that the deduction should be accounted for as a special deduction in accordance with SFAS 109, which means that the tax benefit is recognized as realized, rather than as a one-time benefit due to a reduction of deferred tax liabilities. This FSP was effective upon issuance. The Company cannot predict what impact the Act will have on net income in future periods.
SFAS No. 151, Inventory Costs, was issued by the FASB in November 2004. This statement amends Accounting Research Bulletin No. 43, to clarify that abnormal amounts of idle facility expense, freight, handling costs, and wasted materials should be recognized as current-period charges, and it also requires that allocation of fixed production overheads be based on the normal capacity of the related production facilities. The provisions of this statement will be effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The provisions of this statement will be applied prospectively. The Company does not expect the adoption of this statement to have a significant impact on its results of operations.
The FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets an amendment of APB Opinion No. 29, in December 2004. This statement addresses the measurement of exchanges of nonmonetary assets and eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. The provisions of SFAS No. 153 will be effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The provisions of this statement will be applied prospectively. The Company does not expect the adoption of this statement to have a significant impact on its results of operations.
In 2004 the FASB reviewed whether mineral interests in properties (mineral leases) held by oil and gas companies should be recorded and disclosed as intangible assets under the guidance of SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. After consideration of the matter, the FASB issued a staff position stating that drilling and mineral rights of oil and gas producing entities that are within the scope of SFAS 19 are not subject to the intangible asset classification and disclosure rules of SFAS No. 142. The staff position is consistent with the Company’s present accounting practices and had no effect on its financial statements or disclosures.
Note C – Discontinued Operations
The Company sold most of its Western Canadian conventional oil and gas assets (sale properties) in the second quarter of 2004 for net proceeds of $582,973,000. The Company recorded a gain of $171,095,000, net of $23,486,000 in income taxes, from sale of the properties. The Company primarily utilized the proceeds of the sale to repay debt under revolving credit agreements. At the time of sale, the sale properties produced about 20,000 barrels of oil equivalent per day and had total proved reserves of approximately 43 million barrels equivalent from heavy oil, light oil, and natural gas properties. The operating results from the sale properties have been reported as discontinued operations beginning in the first quarter of 2004. Operating results for the years ended December 31, 2003 and 2002 have been reclassified to conform to this presentation. These sale properties were formerly included in the Canadian exploration and production segment. The major assets (liabilities) associated with the sale properties were as follows at the time of the sale:
(Thousands of dollars) | ||||
Inventory | $ | 1,741 | ||
Prepaid expense | 907 | |||
Property, plant and equipment, net of accumulated depreciation, depletion and amortization | 407,982 | |||
Goodwill, net | 23,091 | |||
Other noncurrent assets | 4,214 | |||
Assets sold | $ | 437,935 | ||
Deferred income taxes | $ | (25,092 | ) | |
Asset retirement obligations | (49,543 | ) | ||
Liabilities associated with assets sold | $ | (74,635 | ) | |
Additionally, in December 2002, the Company sold its interest in Ship Shoal Block 113 in the Gulf of Mexico for an after-tax gain of $10,650,000.
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The following table reflects the results of operations from the properties disposed of including gains on sale.
| Year Ended December 31, | |||||||
(Thousands of dollars) | 2004 | 2003 | 2002 | ||||
Revenues, including a pretax gain on sale of assets of $194,581 in 2004 and $16,384 in 2002 | $ | 274,568 | 207,387 | 246,482 | |||
Income before income tax expense | 244,676 | 44,962 | 51,644 | ||||
Income tax expense | 39,756 | 22,182 | 27,415 | ||||
Note D – Property, Plant and Equipment
| December 31, 2004 | December 31, 2003 | ||||||||||
(Thousands of dollars) | Cost | Net | Cost | Net | |||||||
Exploration and production | $ | 4,773,328 | 2,634,962 | * | 5,294,386 | 2,538,131 | * | ||||
Refining | 1,165,494 | 565,138 | 1,104,589 | 555,822 | |||||||
Marketing | 632,255 | 462,298 | 558,046 | 412,550 | |||||||
Corporate and other | 47,731 | 23,196 | 45,912 | 24,297 | |||||||
| $ | 6,618,808 | 3,685,594 | 7,002,933 | 3,530,800 | |||||||
| * | Includes $21,527 in 2004 and $22,006 in 2003 related to administrative assets and support equipment. |
In the Consolidated Statements of Income, the Company recorded noncash charges of $8,314,000 in 2003 and $31,640,000 in 2002 for impairment of certain properties. After related income tax benefits, these write-downs reduced net income by $5,404,000 in 2003 and $20,567,000 in 2002. The 2003 charge included $5,314,000 to write-down the cost of a refined product terminal to be closed and certain components of the Meraux refinery that were rendered obsolete upon completion of the refinery upgrade, and $3,000,000 to write-down the cost of a natural gas field in the Gulf of Mexico due to downward revisions in reserves caused by poor well performance. The 2002 charge included $22,487,000 to write-down the remaining cost in Destin Dome Blocks 56 and 57, offshore Florida. In 2002, Murphy reached an agreement with the U.S. government that restricts the Company’s ability to seek approval for development of this natural gas discovery until at least 2012. The additional charges in 2002 were caused by downward reserve revisions for poor well performance of natural gas fields in the Gulf of Mexico. The carrying value of impaired properties were reduced to the asset’s fair value based on projected future discounted net cash flows using the Company’s estimate of future commodity prices.
During the three years ended December 31, 2004, the Company sold certain oil and gas properties and other assets and recorded before tax gains of $69,594,000 in 2004, $61,524,000 in 2003 and $9,148,000 in 2002. The primary assets sold were the “T” Block field in 2004 and the Ninian and Columba fields in 2003; all of these fields are in the U.K. section of the North Sea.
The FASB has issued proposed FASB Staff Position No. FAS 19-a (FSP 19-a), which had a comment deadline of March 7, 2005. FSP 19-a would alter the present rules of SFAS 19 paragraphs 31 and 34 regarding when exploration drilling costs can be held on the books of an oil and gas company that uses the successful efforts accounting method. While the FASB is completing their review of this issue, the Securities and Exchange Commission has requested that oil and gas companies disclose certain information about their exploratory drilling costs. The following information is in response to the SEC’s request.
At December 31, 2004 and 2003, the Company had total capitalized drilling costs pending the determination of proved reserves of $106,105,000 and $158,034,000, respectively. Most capitalized drilling costs that were carried in the balance sheet as of December 31, 2004 and 2003 pending the determination of proved reserves had additional drilling wells under way or firmly planned; for one well drilled in 2004 at a cost of $6,917,000, the Company was reviewing its development options. At December 31, 2003, the Company held one well in property with a cost of $2,236,000 that was drilled more than one year earlier pending approval of a development plan by a foreign government. This well was on production by year-end 2004.
The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 2004.
(Thousands of dollars) | 2004 | 2003 | 2002 | ||||||
Beginning balance at January 1 | $ | 158,034 | 72,556 | 1,457 | |||||
Additions to capitalized exploratory well costs pending the determination of proved reserves | 94,048 | 85,478 | 71,421 | ||||||
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves | (125,211 | ) | — | (322 | ) | ||||
Capitalized exploratory well costs charged to expense or sold | (20,766 | ) | — | — | |||||
Ending balance at December 31 | $ | 106,105 | 158,034 | 72,556 | |||||
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The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling.
(Thousands of dollars) | 2004 | 2003 | 2002 | ||||
Capitalized exploratory well costs capitalized for one year or less | $ | 93,956 | 82,262 | 71,368 | |||
Capitalized exploratory well costs capitalized for more than one year but less than two years | 12,149 | 74,330 | 1,188 | ||||
Capitalized exploratory well costs capitalized for more than two years but less than three years | — | 1,442 | — | ||||
Balance at December 31 | $ | 106,105 | 158,034 | 72,556 | |||
Number of projects that have exploratory well costs that have been capitalized for one year or more | 1 | 7 | 2 | ||||
Based on the Company’s present understanding of the proposed FSP 19-a, we would not expect the adoption of this statement, as it is currently written, to cause us to expense any exploration drilling costs held on the books at year-end 2004. In addition, the application of this proposed standard during the three-year period ended December 31, 2004 would not have significantly changed the net income reported during any of the applicable years.
Note E – Financing Arrangements
At December 31, 2004, the Company had two committed credit facilities with a major banking consortium totaling US $700,000,000. The Company and a subsidiary may borrow under a US $150,000,000 revolving credit agreement and the Company has available a US $550,000,000 revolving credit agreement. Both of these facilities mature in December 2006. Depending on the credit facility, borrowings bear interest at prime or varying cost of fund options. Facility fees are due at varying rates on the commitments. The Company also had uncommitted lines of credit with banks at December 31, 2004 totaling an equivalent US $392,000,000 for a combination of U.S. dollar and Canadian dollar borrowings. 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 US $650,000,000 in debt and equity securities.
Note F – Long-term Debt
| December 31 | |||||||
(Thousands of dollars) | 2004 | 2003 | |||||
Notes payable | |||||||
6.375% notes, due 2012, net of unamortized discount of $843 at December 31, 2004 | $ | 349,157 | 349,038 | ||||
7.05% notes, due 2029, net of unamortized discount of $2,263 at December 31, 2004 | 247,737 | 247,649 | |||||
6.23% structured loan, due 2005 | 46,277 | 82,854 | |||||
Notes payable to bank | — | 417,500 | |||||
Other, 6% to 8%, due 2005-2021 | 956 | 1,046 | |||||
Total notes payable | 644,127 | 1,098,087 | |||||
Nonrecourse debt of a subsidiary | |||||||
Guaranteed credit facilities with banks Commercial paper supported by credit facility | — | 37,000 | |||||
Loans payable to Canadian government, interest free, payable in Canadian dollars, due 2005-2009 | 19,955 | 22,444 | |||||
Total nonrecourse debt of a subsidiary | 19,955 | 59,444 | |||||
Total debt including current maturities | 664,082 | 1,157,531 | |||||
Current maturities | (50,727 | ) | (67,224 | ) | |||
Total long-term debt | $ | 613,355 | 1,090,307 | ||||
Maturities for the four years after 2005 are: $4,351,000 in 2006, $4,342,000 in 2007, $4,344,000 in 2008 and $2,622,000 in 2009.
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 is reduced in quarterly installments. Payment of interest under the loan has been guaranteed by the Company.
In accordance with the terms of the agreement, all amounts previously outstanding under a guaranteed credit facility were prepaid in 2004.
The interest-free loans from the Canadian government were used to finance expenditures for the Hibernia field. The outstanding balance is primarily to be repaid in equal annual installments through 2009.
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Note G – Asset Retirement Obligations
On January 1, 2003, the Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations, which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement obligation (ARO) liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed in service. When the liability is initially recorded, the Company will increase the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability is recognized as a gain or loss in the Company’s earnings. The estimation of the future asset retirement obligation is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that may be required in future periods due to the availability of additional information such as: prices for oil field services, technological changes, governmental requirements and other factors. Upon adoption of SFAS No. 143, the Company recorded a charge of $6,993,000, net of $1,400,000 in income taxes, as the cumulative effect of a change in accounting principle. The noncash transition adjustment increased property, plant and equipment, accumulated depreciation, and asset retirement obligations by $142,894,000, $58,786,000, and $92,500,000, respectively.
The majority of the ARO recognized by the Company at December 31, 2004 and 2003 relates to the estimated costs to dismantle and abandon its producing oil and gas properties and related equipment. A portion of the ARO relates to retail gasoline stations. The Company did not record an ARO for its refining and certain of its marketing assets because sufficient information is presently not available to estimate a range of potential settlement dates for the obligation. These assets are consistently being upgraded and are expected to be operational into the foreseeable future. In these cases, the obligation will be initially recognized in the period in which sufficient information exists to estimate the obligation.
A reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligation is shown in the following table.
(Thousands of dollars) | 2004 | 2003 | |||||
Balance at beginning of year | $ | 252,397 | 160,543 | ||||
Transition adjustment | — | 92,500 | |||||
Accretion expense | 11,226 | 12,366 | |||||
Liabilities incurred | 20,340 | 28,210 | |||||
Revision of previous estimates | 2,602 | — | |||||
Liabilities settled | (87,453 | ) | (67,234 | ) | |||
Changes due to translation of foreign currencies | 2,820 | 26,012 | |||||
Balance at end of year | $ | 201,932 | 252,397 | ||||
Accretion expense of $1,209,000 and $2,632,000 shown in the above table were included in discontinued operations for the year ended December 31, 2004 and 2003, respectively. Liabilities settled in 2004 and 2003 included approximately $76,932,000 and $62,578,000, respectively, in noncash reductions of ARO associated with the sale of certain oil and gas producing properties.
The pro forma ARO as of January 1, 2002 was $224,466,000. Pro forma net income for the year ended December 31, 2002, assuming SFAS No. 143 had been applied retroactively, is shown in the following table.
(Thousands of dollars except per share data) | 2002 | ||||
Net income | – As reported | $ | 111,508 | ||
Pro forma | 113,803 | ||||
Net income per share | – As reported, basic | $ | 1.22 | ||
Pro forma, basic | 1.24 | ||||
As reported, diluted | 1.21 | ||||
Pro forma, diluted | 1.23 | ||||
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Note H – Income Taxes
The components of income from continuing operations before income taxes for each of the three years ended December 31, 2004 and income tax expense (benefit) attributable thereto were as follows.
(Thousands of dollars) | 2004 | 2003 | 2002 | |||||||
Income (loss) from continuing operations before income taxes | ||||||||||
United States | $ | 244,758 | (50,296 | ) | (128,523 | ) | ||||
Foreign | 560,178 | 424,501 | 250,089 | |||||||
| $ | 804,936 | 374,205 | 121,566 | |||||||
Income tax expense (benefit) from continuing operations | ||||||||||
Federal – Current1 | $ | 22,446 | (5,321 | ) | (41,531 | ) | ||||
Deferred | 78,446 | (11,911 | ) | (1,349 | ) | |||||
Noncurrent | (1,339 | ) | (18,217 | ) | (6,824 | ) | ||||
| 99,553 | (35,449 | ) | (49,704 | ) | ||||||
State | 2,154 | 84 | (529 | ) | ||||||
Foreign – Current | 194,405 | 96,795 | 73,622 | |||||||
Deferred2 | 13,759 | 24,715 | 13,786 | |||||||
Noncurrent | (1,330 | ) | 9,650 | (2,888 | ) | |||||
| 206,834 | 131,160 | 84,520 | ||||||||
Total | $ | 308,541 | 95,795 | 34,287 | ||||||
| 1 | Net of benefit of $10,939 in 2002 for alternative minimum tax credits. |
| 2 | Includes a benefit of $4,923 in 2004 and $10,101 in 2003 for enacted reductions in federal and provincial tax rates in Canada and a charge of $1,997 in 2002 for an enacted increase in the U.K. tax rate for North Sea oil production. |
Income tax benefits attributable to employee stock option transactions of $553,000 in 2004, $467,000 in 2003 and $3,833,000 in 2002 were included in Capital in Excess of Par Value in the Consolidated Balance Sheets. Income tax (benefits) charges of $2,712,000 in 2004, $(11,549,000) in 2003 and $(8,885,000) in 2002 relating to derivatives were included in Accumulated Other Comprehensive Income (AOCI).
Total income tax expense in 2004, 2003 and 2002, including taxes associated with discontinued operations and the cumulative effect of a change in accounting principle, was $348,297,000, $116,577,000, and $61,702,000, respectively.
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 from continuing operations and before cumulative effect of accounting change.
(Thousands of dollars) | 2004 | 2003 | 2002 | |||||||
Income tax expense based on the U.S. statutory tax rate | $ | 281,727 | 130,971 | 42,548 | ||||||
Foreign income subject to foreign taxes at a rate different than the U.S. statutory rate | 23,002 | 9,865 | 1,900 | |||||||
Canadian withholding tax and federal tax on dividend | 45,863 | — | — | |||||||
State income taxes, net of federal benefit | 1,400 | 54 | (344 | ) | ||||||
Settlement of U.S. and foreign taxes | (5,545 | ) | (20,146 | ) | (8,134 | ) | ||||
Changes in foreign tax rates | (4,923 | ) | (10,101 | ) | 1,997 | |||||
Recognition of deferred income tax benefit related to exploration and other expenses in Malaysia | (31,858 | ) | (11,410 | ) | — | |||||
Other, net | (1,125 | ) | (3,438 | ) | (3,680 | ) | ||||
Total | $ | 308,541 | 95,795 | 34,287 | ||||||
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Table of Contents
An analysis of the Company’s deferred tax assets and deferred tax liabilities at December 31, 2004 and 2003 showing the tax effects of significant temporary differences follows.
(Thousands of dollars) | 2004 | 2003 | |||||
Deferred tax assets | |||||||
Property and leasehold costs | $ | 118,179 | 107,690 | ||||
Liabilities for dismantlements and major repairs | 88,580 | 96,179 | |||||
Postretirement and other employee benefits | 58,770 | 49,785 | |||||
Federal alternative minimum tax credit carryforward | 3,651 | 15,477 | |||||
Federal operating loss carryforward | — | 48,795 | |||||
Foreign tax operating losses | 6,267 | 5,236 | |||||
Other deferred tax assets | 62,139 | 29,388 | |||||
Total gross deferred tax assets | 337,586 | 352,550 | |||||
Less valuation allowance | (61,337 | ) | (68,050 | ) | |||
Net deferred tax assets | 276,249 | 284,500 | |||||
Deferred tax liabilities | |||||||
Property, plant and equipment | (82,048 | ) | (75,940 | ) | |||
Accumulated depreciation, depletion and amortization | (521,311 | ) | (467,105 | ) | |||
Other deferred tax liabilities | (187,759 | ) | (135,211 | ) | |||
Total gross deferred tax liabilities | (791,118 | ) | (678,256 | ) | |||
Net deferred tax liabilities* | $ | (514,869 | ) | (393,756 | ) | ||
| * | Includes deferred tax asset in Malaysia of $30,777,000 and $7,004,000 reported in Deferred Charges and Other Assets in the Consolidated Balance Sheet as of December 31, 2004 and 2003, respectively. |
During 2003, the Company generated a net operating loss carryforward for Federal income tax purposes of $139,414,000 that was fully utilized during 2004 to offset Federal taxable income. At December 31, 2004 the Company has alternative minimum tax credit carryforwards of $3,651,000, which are available to reduce future Federal regular income taxes over an indefinite period.
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 Company recorded deferred tax benefits of $31,858,000 in 2004 and $11,410,000 in 2003 to recognize anticipated future tax benefits on exploration and other expenses related to Blocks K, SK 309 and 311 in Malaysia. Excluding the changes described for Malaysia above, the valuation allowance increased $25,145,000 in 2004 and decreased $10,114,000 in 2003, with these changes primarily offsetting 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.
Subsidiaries included in the Company’s U.S. consolidated tax return record income tax expense as though they filed separate tax returns. The parent records adjustments to income tax expense for the effects of consolidation. Income taxes are accrued for retained earnings of certain international subsidiaries and corporate joint ventures intended to be remitted. Income taxes are not accrued for unremitted earnings of international operations that are indefinitely reinvested.
During 2004, the Company recorded income tax expense of $45,863,000 related to repatriation of U.K. and Canadian earnings to the U.S. The most significant portion of this expense related to a 5% withholding tax on funds repatriated from Canada. This tax was not recorded in prior years because, until the sale of most Western Canadian assets occurred in 2004, these funds were considered permanently invested, and therefore, met the criteria for not recording income tax expense. The Company does not record deferred income taxes related to undistributed earnings of international subsidiaries because such earnings are considered permanently invested. Foreign tax credits are available for most of these undistributed earnings. A 5% withholding tax would be payable on any currently unplanned future repatriation of earnings from Canada, and as of December 31, 2004, this withholding tax would amount to $37,490,000. The American Jobs Creation Act of 2004 (the Act) provides for a special one-time dividends received tax deduction on repatriation of certain foreign earnings into the U.S. The Company is evaluating the Act to determine how it may affect future decisions on foreign earnings repatriation.
Tax returns are subject to audit by various taxing authorities. In 2004, 2003 and 2002, the Company recorded benefits to income of $5,545,000, $20,146,000 and $14,737,000, respectively, from settlements of U.S. and foreign tax issues primarily related to prior years. Although the Company believes that adequate accruals have been made for unsettled issues, additional gains or losses could occur in future years from resolution of outstanding matters.
F-16
Table of Contents
Note I – Incentive Plans
The Company’s 1992 Stock Incentive Plan (1992 Plan) authorized the Executive Compensation 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% of shares outstanding at the end of the preceding year; allowed shares not granted may be granted in future years. In addition, shareholders approved the Stock Plan for Non-Employee Directors (2003 Plan) in 2003. This plan permits the issuance of restricted stock, stock options or a combination thereof to the Company’s Directors. The Company uses APB Opinion No. 25 to account for stock-based compensation, accruing costs of restricted stock and any stock options deemed to be variable in nature over the vesting/performance periods and adjusting costs for changes in fair market value of Common Stock. Compensation cost charged against income for stock-based plans was $3,122,000 in 2004, $303,000 in 2003, and $5,288,000 in 2002. Outstanding awards were not modified in the last three years.
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 7 to 10 years, has been nonqualified, and has had an option price equal to or higher than FMV at date of grant. Under the 1992 Plan, one-half of each grant may be exercised after two years and the remainder after three years. Under the 2003 Plan, one-third of each grant may be exercised after each of the first three years.
Changes in options outstanding, including shares issued under a prior plan, were as follows.
| Number of Shares | Average Exercise Price | |||||
Outstanding at December 31, 2001 | 3,418,740 | $ | 26.74 | |||
Granted at FMV | 945,000 | 38.85 | ||||
Exercised | (983,400 | ) | 23.44 | |||
Forfeited | (83,500 | ) | 31.20 | |||
Outstanding at December 31, 2002 | 3,296,840 | 31.08 | ||||
Granted at FMV | 845,500 | 43.09 | ||||
Exercised | (86,500 | ) | 26.02 | |||
Forfeited | (21,280 | ) | 35.30 | |||
Outstanding at December 31, 2003 | 4,034,560 | 33.59 | ||||
Granted at FMV | 544,230 | 60.61 | ||||
Exercised | (60,000 | ) | 27.63 | |||
Outstanding at December 31, 2004 | 4,518,790 | 36.93 | ||||
Exercisable at December 31, 2002 | 988,340 | $ | 25.01 | |||
Exercisable at December 31, 2003 | 1,777,060 | 27.32 | ||||
Exercisable at December 31, 2004 | 2,686,060 | 30.06 | ||||
Additional information about stock options outstanding at December 31, 2004 is shown below.
| Options Outstanding | Options Exercisable | |||||||||||
Range of Exercise | No. of Options | Avg. Life in Years | Avg. Price | No. of Options | Avg. Price | |||||||
$17.84 to $ 21.12 | 244,060 | 3.8 | $ | 18.05 | 244,060 | $ | 18.05 | |||||
$24.88 to $ 28.48 | 894,500 | 4.3 | 27.47 | 894,500 | 27.47 | |||||||
$30.23 to $ 32.74 | 1,068,500 | 5.7 | 30.89 | 1,068,500 | 30.89 | |||||||
$38.85 to $ 47.16 | 1,767,500 | 7.0 | 40.67 | 479,000 | 39.16 | |||||||
$60.59 to $ 76.36 | 544,230 | 9.1 | 60.61 | — | — | |||||||
| 4,518,790 | 6.2 | $ | 36.93 | 2,686,060 | $ | 30.06 | ||||||
F-17
Table of Contents
The pro forma net income calculations in Note A reflect the following fair values of stock options granted in 2004, 2003 and 2002; fair values of options have been estimated using the Black-Scholes pricing model and the weighted-average assumptions as shown.
| 2004 | 2003 | 2002 | ||||||||||
Fair value per option at grant date | $ | 14.92 | $ | 10.32 | $ | 9.59 | ||||||
Assumptions | ||||||||||||
Dividend yield | 1.86 | % | 2.12 | % | 2.56 | % | ||||||
Expected volatility | 27.81 | % | 28.77 | % | 26.80 | % | ||||||
Risk-free interest rate | 3.24 | % | 3.01 | % | 4.89 | % | ||||||
Expected life | 5 yrs. | 5 yrs. | 5 yrs. | |||||||||
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 the performance period. Such performance periods have ranged from three to five years in length. 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. In 2002, eligible shares granted in 1998 were awarded to the grantees, and additional shares were awarded in 2003 based on financial objectives achieved. Changes in restricted stock outstanding were as follows.
(Number of shares) | 2004 | 2003 | 2002 | ||||||
Balance at beginning of year | — | — | 115,166 | ||||||
Granted | 85,450 | 64,084 | — | ||||||
Awarded | — | (64,084 | ) | (115,166 | ) | ||||
Forfeited | (638 | ) | — | — | |||||
Balance at end of year | 84,812 | — | — | ||||||
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 $13,663,000, $14,931,000 and $3,911,000 was recorded in 2004, 2003 and 2002, respectively, for these plans.
EMPLOYEE STOCK PURCHASE PLAN (ESPP) – The Company has an ESPP under which 300,000 shares of the Company’s Common Stock could be purchased by eligible U.S. and Canadian employees. Each quarter, an eligible 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 300,000 shares or June 30, 2007. Employee stock purchases under the ESPP were 20,330 shares at an average price of $63.85 per share in 2004, 30,128 shares at $44.81 in 2003 and 24,828 shares at $38.94 in 2002. At December 31, 2004, 91,455 shares remained available for sale under the ESPP. Compensation costs related to the ESPP were immaterial.
Note J – Employee and Retiree Benefit Plans
PENSION AND POSTRETIREMENT PLANS – The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors’ plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.
F-18
Table of Contents
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, 2004 and 2003 and a statement of the funded status as of December 31, 2004 and 2003.
| Pension Benefits | Postretirement Benefits | ||||||||||||
(Thousands of dollars) | 2004 | 2003 | 2004 | 2003 | |||||||||
Change in benefit obligation | |||||||||||||
Obligation at January 1 | $ | 330,577 | 296,638 | 65,774 | 53,668 | ||||||||
Service cost | 8,332 | 7,347 | 1,707 | 1,236 | |||||||||
Interest cost | 19,478 | 18,753 | 3,507 | 3,687 | |||||||||
Plan amendments | — | 548 | — | (4,184 | ) | ||||||||
Participant contributions | 55 | 63 | 554 | 689 | |||||||||
Actuarial loss (gain) | 10,704 | 13,846 | (8,227 | ) | 14,476 | ||||||||
Curtailments | — | (568 | ) | — | — | ||||||||
Exchange rate changes | 6,227 | 8,081 | — | — | |||||||||
Benefits paid | (16,665 | ) | (14,131 | ) | (3,975 | ) | (3,798 | ) | |||||
Special termination benefits | (2,820 | ) | — | — | — | ||||||||
Other | — | — | (824 | ) | — | ||||||||
Obligation at December 31 | 355,888 | 330,577 | 58,516 | 65,774 | |||||||||
Change in plan assets | |||||||||||||
Fair value of plan assets at January 1 | 261,182 | 234,432 | — | — | |||||||||
Actual return on plan assets | 16,170 | 30,833 | — | — | |||||||||
Employer contributions | 5,051 | 2,584 | 3,421 | 3,109 | |||||||||
Participant contributions | 55 | 63 | 554 | 689 | |||||||||
Settlements | (2,693 | ) | (436 | ) | — | — | |||||||
Exchange rate changes | 5,532 | 7,837 | — | — | |||||||||
Benefits paid | (16,665 | ) | (14,131 | ) | (3,975 | ) | (3,798 | ) | |||||
Fair value of plan assets at December 31 | 268,632 | 261,182 | — | — | |||||||||
Reconciliation of funded status | |||||||||||||
Funded status at December 31 | (87,256 | ) | (69,395 | ) | (58,516 | ) | (65,774 | ) | |||||
Unrecognized actuarial loss | 95,025 | 82,250 | 22,798 | 33,321 | |||||||||
Unrecognized transition asset | (4,635 | ) | (5,596 | ) | — | — | |||||||
Unrecognized prior service cost | 5,402 | 6,151 | (3,813 | ) | (4,090 | ) | |||||||
Net plan asset (liability) recognized | $ | 8,536 | 13,410 | (39,531 | ) | (36,543 | ) | ||||||
Amounts recognized in the Consolidated Balance Sheets at December 31 | |||||||||||||
Prepaid benefit asset | $ | 3,964 | 4,460 | — | — | ||||||||
Accrued benefit liability | (57,045 | ) | (44,819 | ) | (39,531 | ) | (36,543 | ) | |||||
Intangible asset | 4,421 | 4,122 | — | — | |||||||||
Accumulated other comprehensive loss* | 57,196 | 49,647 | — | — | |||||||||
Net plan asset (liability) recognized | $ | 8,536 | 13,410 | (39,531 | ) | (36,543 | ) | ||||||
| * | Before reduction for associated deferred taxes of $19,461 at December 31, 2004 and $16,846 at December 31, 2003. |
At December 31, 2003, a minimum pension liability adjustment was required for certain of the Company’s plans. For these plans, accumulated benefit obligations exceeded the fair value of plan assets by $57,681,000. After reductions for amounts charged to intangible assets, net of associated deferred income taxes, charges that reduce accumulated other comprehensive income of $4,934,000 and $31,449,000 were recorded in 2004 and 2003, respectively.
F-19
Table of Contents
The table that follows includes projected benefit obligations (PBO), accumulated benefit obligations and fair value of plan assets for plans where the PBO exceeded the fair value of plan assets.
| Projected Benefit Obligations | Accumulated Benefit Obligations | Fair Value of Plan Assets | |||||||||||
(Thousands of dollars) | 2004 | 2003 | 2004 | 2003 | 2004 | 2003 | |||||||
Funded qualified plans where PBO exceeds fair value of plan assets | $ | 316,271 | 291,473 | 278,632 | 255,873 | 239,067 | 232,535 | ||||||
Unfunded nonqualified and directors’ plans where PBO exceeds fair value of plan assets | 25,578 | 24,391 | 20,562 | 18,493 | — | — | |||||||
Unfunded postretirement plans | 58,516 | 65,774 | 39,531 | 36,543 | — | — | |||||||
The table that follows provides the components of net periodic benefit expense (credit) for each of the three years ended December 31, 2004.
| Pension Benefits | Postretirement Benefits | |||||||||||||||||
(Thousands of dollars) | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||
Service cost | $ | 8,332 | 7,347 | 6,721 | 1,707 | 1,236 | 1,287 | |||||||||||
Interest cost | 19,478 | 18,753 | 18,097 | 3,507 | 3,687 | 3,280 | ||||||||||||
Expected return on plan assets | (18,620 | ) | (17,275 | ) | (19,791 | ) | — | — | — | |||||||||
Amortization of prior service cost | 785 | 764 | 778 | (277 | ) | (95 | ) | — | ||||||||||
Amortization of transitional asset | (636 | ) | (2,052 | ) | (2,559 | ) | — | — | — | |||||||||
Recognized actuarial loss | 4,554 | 3,664 | 1,242 | 1,347 | 1,334 | 633 | ||||||||||||
| 13,893 | 11,201 | 4,488 | 6,284 | 6,162 | 5,200 | |||||||||||||
Curtailment expense | — | 338 | — | — | — | — | ||||||||||||
Settlement gain | (1,069 | ) | — | — | — | — | — | |||||||||||
Net periodic benefit expense | $ | 12,824 | 11,539 | 4,488 | 6,284 | 6,162 | 5,200 | |||||||||||
Settlement gains in 2004 related to employee reductions associated with the sale of Western Canadian conventional oil and gas properties. Curtailment expense in 2003 recorded unrecognized prior service costs related to the freezing of benefits under the Directors’ retirement plan.
The preceding tables in this note include the following amounts related to foreign benefit plans.
| Pension Benefits | Postretirement Benefits | ||||||||||
(Thousands of dollars) | 2004 | 2003 | 2004 | 2003 | |||||||
Benefit obligation at December 31 | $ | 85,752 | 72,067 | — | — | ||||||
Fair value of plan assets at December 31 | 74,596 | 67,396 | — | — | |||||||
Net plan liability recognized | (408 | ) | (4,181 | ) | — | — | |||||
Net periodic benefit expense | 613 | 1,431 | — | — | |||||||
The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2004 and 2003 and net periodic benefit expense for the years 2004 and 2003.
| Benefit Obligations | Net Periodic Benefit Expense | |||||||||||||||||||||||
| Pension Benefits | Postretirement Benefits | Pension Benefits | Postretirement Benefits | |||||||||||||||||||||
| December 31, | December 31, | Year | Year | |||||||||||||||||||||
| 2004 | 2003 | 2004 | 2003 | 2004 | 2003 | 2004 | 2003 | |||||||||||||||||
Discount rate | 5.89 | % | 6.11 | % | 6.00 | % | 6.25 | % | 6.08 | % | 6.53 | % | 6.25 | % | 6.75 | % | ||||||||
Expected return on plan assets | 7.42 | % | 7.46 | % | — | — | 7.42 | % | 7.46 | % | — | — | ||||||||||||
Rate of compensation increase | 4.07 | % | 4.04 | % | — | — | 4.07 | % | 4.04 | % | — | — | ||||||||||||
Discount rates are adjusted as necessary, generally based on changes in AA-rated corporate bond rates. Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics. Expected compensation increases are based on historical averages for the Company.
F-20
Table of Contents
The weighted average asset allocation for the Company’s benefit plans at the annual measurement dates of September 30, 2004 and 2003 are presented in the following table.
| September 30, | ||||||
| 2004 | 2003 | |||||
Equity securities | 53.5 | % | 53.9 | % | ||
Debt securities | 42.4 | 41.7 | ||||
Cash | 4.1 | 4.4 | ||||
| 100.0 | % | 100.0 | % | |||
The Company has directed the asset investment advisors of its benefit plans to maintain a portfolio nearly balanced between equity and debt securities. The investment advisors may vary the asset mix within the range of 40%-60% for both equity and debt securities. The Company believes that a balanced portfolio of equity and debt securities represents the best long-term mix for future return on domestic plans’ assets. Investment advisors are not permitted to invest benefit plan assets in Murphy Oil’s common stock.
The Company’s expected return on plan assets was 7.42% in 2004 and the return was determined based on an assessment of actual long-term historical returns and expected future returns for a balanced portfolio similar to that maintained by the plans. The 7.42% expected return was based on an expected average future equity asset return of 9.1% and a return on high-quality corporate bonds of 5.6%, and is net of average expected investment expenses of .38%. Over the last 10 years, the return on funded retirement plan assets has averaged 9.3%.
The Company currently expects to make contributions of $4,833,000 to its domestic defined benefit pension plans, $7,261,000 to its foreign defined pension plans, and $2,932,000 to its domestic postretirement benefits plan during 2005.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid from the assets of the plans or by the Company:
(Thousands of dollars) | Pension Benefits | Postretirement Benefits | |||
2005 | $ | 17,170 | 2,932 | ||
2006 | 17,591 | 3,032 | |||
2007 | 18,168 | 3,119 | |||
2008 | 18,661 | 3,152 | |||
2009 | 19,284 | 3,291 | |||
2010-2014 | 110,405 | 19,311 | |||
For purposes of measuring postretirement benefit obligations at December 31, 2004, the future annual rates of increase in the cost of health care were assumed to be 7.0% for 2005 decreasing 0.5% per year to an ultimate rate of 5.0% in 2009 and thereafter.
Assumed health care cost trend rates have a significant effect on the expense and obligation reported for the postretirement benefit plan. A 1% change in assumed health care cost trend rates would have the following effects.
(Thousands of dollars) | 1% Increase | 1% Decrease | ||||
Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 2004 | $ | 925 | (731 | ) | ||
Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2004 | 8,726 | (7,067 | ) | |||
On December 8, 2003, the President signed the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). Among other provisions, the Act changed prescription drug coverage under Medicare beginning in 2006. Generally, companies that provide qualifying prescription drug coverage that is deemed actuarially equivalent to medicare coverage for retirees aged 65 and above will be eligible to receive a federal subsidy equal to 28% of drug costs between $250 and $5,000 per annum for each covered individual that does not elect to receive coverage under the new Medicare Part D. The Company currently provides prescription drug coverage to qualifying retirees under its retiree medical plan. As a result of provisions in the Act, the Company’s accumulated postretirement benefit obligation was reduced by approximately $6,715,000 and its postretirement benefit expense was approximately $1,000,000 lower during 2004.
THRIFT PLANS – Most full-time 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. A U.K. savings plan allows eligible employees to allot a portion of their base pay to purchase Company Common Stock at market value. Such employee allotments are matched by the Company. Common Stock issued from the Company’s treasury under this U.K. savings plan was 3,302 shares in 2004, 432 shares in 2003 and 12,417 shares in 2002. Amounts charged to expense for these U.S. and U.K. plans were $4,895,000 in 2004, $5,377,000 in 2003 and $4,159,000 in 2002.
F-21
Table of Contents
Note K – Financial Instruments and Risk Management
DERIVATIVE INSTRUMENTS – Murphy utilizes derivative instruments 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 speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange. To qualify for hedge accounting, the changes in the market value of a derivative instrument must historically have been, and would be expected to continue to be, highly effective at offsetting changes in the prices of the hedged item. To the extent that the change in fair value of a derivative instrument has less than perfect correlation with the change in the fair value of the hedged item, a portion of the change in fair value of the derivative instrument is considered ineffective and would normally be recorded in earnings during the affected period.
| • | Interest Rate Risks – Murphy enters into variable-rate debt obligations that expose the Company to the effects of changes in interest rates. To partially reduce its exposure to interest rate risk, Murphy had interest rate swap agreements with notional amounts totaling $50 million at December 31, 2003 to hedge fluctuations in cash flows of a similar amount of variable rate debt. The swaps matured in 2004. Under the interest rate swaps, the Company paid fixed rates averaging 5.98% over their composite lives and received variable rates. The variable rate received by the Company under each contract was repriced quarterly. The Company has a risk management control system to monitor interest rate cash flow risk attributable to the Company’s outstanding and forecasted debt obligations as well as the offsetting interest rate swaps. The control system involves using analytical techniques, including cash flow sensitivity analysis, to estimate the impact of interest rate changes on future cash flows. The fair value of the effective portions of the interest rate swaps and changes thereto was deferred in Accumulated Other Comprehensive Income (AOCI) and was subsequently reclassified into Interest Expense in the periods in which the hedged interest payments on the variable-rate debt affected earnings. For the three-year period ended December 31, 2004, the income effect from cash flow hedging ineffectiveness of interest rates was insignificant. The fair value of the interest rate swaps was estimated using projected Federal funds rates, Canadian overnight funding rates and LIBOR forward curve rates obtained from published indices and counterparties. |
| • | Natural Gas Fuel Price Risks – The Company purchases natural gas as fuel at its Meraux, Louisiana and Superior, Wisconsin refineries, and as such, is subject to commodity price risk related to the purchase price of this gas. Murphy has hedged the cash flow risk associated with the cost of a portion of the natural gas it will purchase in 2005 and 2006 by entering into financial contracts known as natural gas swaps with a remaining notional volume as of December 31, 2004 of 2.2 million MMBTU (1 MMBTU = 1 million British Thermal Units). Other similar contracts covered a portion of 2004 purchases. Under the natural gas swaps, the Company pays a fixed rate averaging $3.35 per MMBTU and receives a floating rate in each month of settlement based on the average NYMEX price for the final three trading days of the month. Murphy has a risk management control system to monitor natural gas price risk attributable both to forecasted natural gas requirements and to Murphy’s natural gas swaps. The control system involves using analytical techniques, including various correlations of natural gas purchase prices to future prices, to estimate the impact of changes in natural gas fuel prices on Murphy’s cash flows. The fair value of the effective portions of the natural gas swaps and changes thereto is deferred in AOCI and is subsequently reclassified into Operating Expenses in the income statements in the periods in which the hedged natural gas fuel purchases affect earnings. During 2003, the Company determined that natural gas swap contract notional volumes with 2004 maturity dates exceeded forecasted 2004 natural gas purchases at its Meraux, Louisiana refinery while the ROSE unit was out of service. Accordingly, natural gas swap contracts with a notional volume of 3.4 million MMBTU at December 31, 2003 no longer qualified as a cash flow hedge. Therefore, 1.3 million MMBTU of these contracts were redesignated as a cash flow hedge of natural gas the Company expected to purchase at its Superior refinery during 2004, and the remaining 2.1 million MMBTU not qualifying as a hedge were marked to fair value through earnings during 2004. Gains of $6,700,000 were recognized in earnings in 2003 as a result of the contracts no longer qualifying as a cash flow hedge. During the first quarter 2004 the Company entered into natural gas price swap agreements with notional volumes of 2.5 million MMBTU that effectively fixed the settlement price of the previously acquired contracts that matured in July through October 2004. The critical terms of all the 2004 contracts were nearly identical. Murphy was required to pay the average NYMEX price for the final three trading days of the month and receive an average natural gas price of $5.235 per MMBTU. The natural gas swap contracts designated as hedges of natural gas the Company will purchase in 2005 through 2006 at the Meraux refinery still qualify as cash flow hedges. For the period ended December 31, 2004, the income effect from cash flow hedging ineffectiveness for these contracts was $472,000, net of $254,000 in income taxes. For the year ended December 31, 2003, the income effect from ineffectiveness was $4,377,000, net of income taxes of $2,357,000. During the year ended December 31, 2004, the Company received approximately $21,798,000 in cash proceeds from maturing swap agreements. |
| • | Natural Gas Sales Price Risks – The sales price of natural gas produced by the Company is subject to commodity price risk. During the first quarter of 2004 Murphy entered into natural gas put options covering a combined United States natural gas sales volume averaging 25,000 MMBTU per day. The strike price provided the Company with a floor price of $4.00 per MMBTU and settled monthly through October 2004. During 2003 Murphy hedged the cash flow risk associated with the sales price for a portion of the natural gas it produced in the United States and Canada by entering into natural gas swap and collar contracts. The swaps covered a combined notional volume averaging 24,200 MMBTU equivalents per day and required Murphy to pay the average relevant index (NYMEX or AECO “C”) price for each month and receive an average price of $3.76 per MMBTU equivalent. The natural gas collars were for a combined notional volume |
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averaging 26,700 MMBTU equivalents per day and provided Murphy with an average floor price of $3.24 per MMBTU and an average ceiling price of $4.64 per MMBTU. Murphy has a risk management control system to monitor natural gas price risk attributable both to forecasted natural gas sales prices and to Murphy’s hedging instruments. The control system involves using analytical techniques, including various correlations of natural gas sales prices to futures prices, to estimate the impact of changes in natural gas prices on Murphy’s cash flows from the sale of natural gas.
The fair values of the effective portions of the natural gas swaps collars and puts and changes thereto were deferred in AOCI and were subsequently reclassified into Sales and Other Operating Revenue in the income statement in the periods in which the hedged natural gas sales affected earnings. For the three-year period ended December 31, 2004, Murphy’s earnings were not significantly affected by cash flow hedging ineffectiveness on natural gas sales price hedges. There were no settlement payments received in the 2004 period relating to the natural gas put options. During 2003, the Company paid $13,107,000 for settlement of natural gas swap and collar agreements. During 2002, the Company received approximately $6,900,000 for settlement of natural gas swap and collar agreements in Canada that were entered into and matured during the year.
| • | Crude Oil Sales Price Risks – The sales price of crude oil produced by the Company is subject to commodity price risk. During 2004 Murphy hedged the cash flow risk associated with the sales price for a portion of its Canadian heavy oil production during 2005 and 2006 by entering into forward sale contracts covering a notional volume of approximately 2,000 barrels per day in 2005 and 4,000 barrels per day in 2006. The Company will pay the average of the posted price at the Hardisty terminal in Canada for each month and receive a fixed price of $29.00 per barrel in 2005 and $25.23 per barrel in 2006. Murphy hedged the cash flow risk associated with the sales price for the crude oil it produced in the United States and a portion of the oil produced in Canada during 2003 by entering into crude oil swap contracts. The swaps covered a notional volume of 22,000 barrels per day of light oil and required Murphy to pay the average of the closing settlement price on the NYMEX for the Nearby Light Crude Futures Contract for each month and receive an average price of $25.30 per barrel. Additionally, there were heavy oil swaps with a notional volume of 10,000 barrels per day that required Murphy to pay the arithmetic average of the posted price at terminals at Kerrobert and Hardisty, Canada for each month and receive an average price of $16.74 per barrel. Murphy has a risk management control system to monitor crude oil price risk attributable both to forecasted crude oil sales prices and to Murphy’s hedging instruments. The control system involves using analytical techniques, including various correlations of crude oil sales prices to futures prices, to estimate the impact of changes in crude oil prices on Murphy’s cash flows from the sale of light and heavy crude oil. |
The fair values of the effective portions of the crude oil sales price hedges and changes thereto were deferred in AOCI and subsequently reclassified into Sales and Other Operating Revenues in the income statement in the periods in which the hedged crude oil sales affected earnings. During 2004, 2003 and 2002, earnings were increased (decreased) by $225,000, $1,507,000 and ($1,371,000), respectively, relating to cash flow hedging ineffectiveness for crude oil sales price hedges. During 2003 the Company paid approximately $66,950,000 for settlement of maturing crude oil sales swaps.
| • | Crude Oil Purchase Price Risks – Each month, the Company purchases crude oil as the primary feedstock for its U.S. refineries. Prior to April 2000, the Company was a party to crude oil swap agreements that limited the exposure of its U.S. refineries to the risks of fluctuations in cash flows resulting from changes in the prices of crude oil purchases in 2002. In April 2000, the Company settled certain of the swaps and entered into offsetting contracts for the remaining swap agreements, locking in a total pretax gain of $7,735,000. The fair values of these settlement gains were recorded in AOCI as part of the transition adjustment at January 1, 2001 and were recognized as a reduction of costs of crude oil purchases in the period the forecasted transactions occurred. Pretax gains of $5,778,000 in 2002 were reclassified from AOCI into earnings. |
During 2005, the Company expects to reclassify approximately $3,602,000 in net after-tax gains from AOCI into earnings as the forecasted transactions covered by hedging instruments actually occur. All forecasted transactions currently being hedged are expected to occur by December 2006.
FAIR VALUE – The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 2004 and 2003. 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. The fair value of investment in marketable securities is estimated based on quotes offered by major financial institutions. The fair value of current and long-term debt is estimated based on current rates offered the Company for debt of the same maturities. The Company has off-balance sheet exposures relating to certain financial guarantees and letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, was nominal.
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| 2004 | 2003 | ||||||||||||
(Thousands of dollars) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||
Financial assets (liabilities): | |||||||||||||
Investment in marketable securities | $ | 17,892 | 17,892 | — | — | ||||||||
Interest rate swaps | — | — | (1,772 | ) | (1,772 | ) | |||||||
Natural gas fuel swaps | 6,099 | 6,099 | 22,750 | 22,750 | |||||||||
Crude oil sales swaps | 594 | 594 | — | — | |||||||||
Current and long-term debt | (664,082 | ) | (791,200 | ) | (1,157,531 | ) | (1,279,040 | ) | |||||
The carrying amounts of interest rate swaps, crude oil swaps and natural gas swaps and collars in the preceding table are included in the Consolidated Balance Sheets in Deferred Charges and Other Assets or Other Accrued Liabilities. Current and long-term debts are included under Current Maturities of Long-Term Debt, Notes Payable and Nonrecourse Debt of a Subsidiary.
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 majority of transactions are major financial institutions.
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 per Common share for each of the three years ended December 31, 2004. No difference existed between net income used in computing basic and diluted income per Common share for these years. There were no antidilutive options for the periods presented.
(Weighted-average shares outstanding) | 2004 | 2003 | 2002 | |||
Basic method | 91,986,321 | 91,814,821 | 91,450,836 | |||
Dilutive stock options | 1,457,190 | 927,945 | 684,131 | |||
Diluted method | 93,443,511 | 92,742,766 | 92,134,967 | |||
Note N – Other Financial Information
INVENTORIES – Inventories accounted for under the LIFO method totaled $139,489,000 and $144,347,000 at December 31, 2004 and 2003, respectively, and these amounts were $219,075,000 and $155,936,000 less than such inventories would have been valued using the FIFO method.
ACCUMULATED OTHER COMPREHENSIVE INCOME – At December 31, 2004 and 2003, the components of Accumulated Other Comprehensive Income were as follows.
(Thousands of dollars) | 2004 | 2003 | |||||
Foreign currency translation gain, net of tax | $ | 167,662 | 88,589 | ||||
Cash flow hedge gains, net of tax | 4,582 | 9,458 | |||||
Minimum pension liability, net of tax | (37,735 | ) | (32,801 | ) | |||
Balance at end of year | $ | 134,509 | 65,246 | ||||
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At December 31, 2004, components of the net foreign currency translation gain of $167,662,000 were gains of $59,883,000 for pounds sterling, $105,185,000 for Canadian dollars and $2,594,000 for other currencies. Comparability of net income was not significantly affected by exchange rate fluctuations in 2004, 2003 and 2002. Net (losses) gains from foreign currency transactions included in the Consolidated Statements of Income were $(26,613,000) in 2004, $4,087,000 in 2003 and $792,000 in 2002.
Foreign currency translation gains shown in the table on the preceding page are net of income taxes of $91,019,000 and $41,054,000 at year-end 2004 and 2003, respectively.
The effect of SFAS Nos. 133/138, Accounting for Derivative Instruments and Hedging Activities, decreased AOCI for the year ended December 31, 2004 by $4,876,000, net of $2,712,000 in income taxes, and increased income by $340,000 for the same period. AOCI increased by $17,912,000, net of $11,549,000 in income taxes, and income increased by $5,988,000 for the year ended December 31, 2003. AOCI decreased by $13,007,000, net of $8,885,000 in income taxes, and income decreased by $1,435,000 for the year ended December 31, 2002.
INSURANCE RECOVERIES – The Company maintains insurance coverage related to losses of production and profits for occurrences such as storms, fires, etc. During 2004, the Company received insurance proceeds of $8,300,000 for lost profits at the Meraux refinery due to the ROSE unit fire in 2003, and $2,000,000 related to loss of production in the Gulf of Mexico associated with Hurricane Lilli in 2002. These amounts were recorded in Sales and Other Operating Revenues in the 2004 Consolidated Statement of Income. The Company expects to collect further insurance receipts for these matters in future periods.
CASH FLOW DISCLOSURES – Cash income taxes paid were $173,580,000, $86,750,000 and $28,531,000 in 2004, 2003 and 2002, respectively. Interest paid, net of amounts capitalized, was $32,141,000, $17,501,000 and $20,977,000 in 2004, 2003 and 2002, respectively.
Noncash operating working capital increased for each of the three years ended December 31, 2004 as follows.
(Thousands of dollars) | 2004 | 2003 | 2002 | |||||||
Accounts receivable | $ | (252,732 | ) | (41,419 | ) | (146,760 | ) | |||
Inventories | (25,335 | ) | (69,166 | ) | (28,196 | ) | ||||
Prepaid expenses | (992 | ) | 15,183 | 1,100 | ||||||
Deferred income tax assets | (10,457 | ) | (1,825 | ) | 662 | |||||
Accounts payable and accrued liabilities | 252,720 | 60,380 | 135,800 | |||||||
Current income tax liabilities | 16,743 | (438 | ) | (3,501 | ) | |||||
Net increase in noncash operating working capital from continuing operations | $ | (20,053 | ) | (37,285 | ) | (40,895 | ) | |||
Note O – Commitments
The Company leases land, gasoline stations and other facilities under operating leases. During the next five years, expected future rental payments under operating leases are approximately $19,967,000 in 2005; $17,615,000 in 2006; $16,916,000 in 2007; $16,000,000 in 2008; and $13,193,000 in 2009. Rental expense for noncancellable operating leases, including contingent payments when applicable, was $27,943,000 in 2004, $32,859,000 in 2003 and $32,087,000 in 2002. To assure long-term supply of hydrogen at its Meraux, Louisiana refinery, the Company has contracted to purchase up to 35 million standard cubic feet of hydrogen per day at market prices through 2019. The contract requires the payment of a base facility charge for use of the facility. Future required minimum annual payments for base facility charges are $6,312,000 in 2005, $6,565,000 in 2006; $6,828,000 in 2007; $7,102,000 in 2008; $7,385,000 in 2009; and $92,207,000 in later years. Base facility charges and hydrogen costs incurred in 2004 and 2003 totaled $27,141,000 and $1,128,000, respectively. The Company has an Operating and Production Handling Agreement providing for processing and production handling services for hydrocarbon production from certain fields in the Gulf of Mexico. This agreement requires minimum annual payments for processing charges for the periods from 2005 through 2009. Under the agreement, the Company must make specified minimum payments quarterly. Future required minimum payments are $19,300,000 in 2005; $15,340,000 in 2006; $12,596,000 in 2007; $9,508,000 in 2008; and $13,272,000 in 2009. In addition, the Company is required to pay additional amounts depending on the actual hydrocarbon quantities processed under the agreement. Processing and handling costs incurred in 2004 were $23,430,000. Additionally, the Company has a Reserved Capacity Service Agreement providing for the availability of needed crude oil storage capacity for certain oil fields through 2020. Under the agreement, the Company must make specified minimum payments monthly. Future required minimum annual payments are $1,866,000 in 2005 through 2009 and $13,433,000 in later years. In addition, the Company is required to pay additional amounts depending on actual crude oil quantities under the agreement. Total payments under the agreement were $2,390,000 in 2004, $1,965,000 in 2003, and $1,435,000 in 2002.
Commitments for capital expenditures were approximately $727,400,000 at December 31, 2004, including $28,300,000 for costs to develop deepwater Gulf of Mexico fields, $63,200,000 for continued expansion of synthetic oil operations in Canada, $394,000,000 for field development and future work commitments in Malaysia, and $37,000,000 for exploration drilling in Congo.
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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 AND LEGAL MATTERS – In addition to being 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 three refineries, five terminals, and approximately 80 service stations for which known or potential obligations for environmental remediation exist. In addition the Company operates or has operated numerous oil and gas fields that may require some form of remediation, which is generally provided for by the Company’s abandonment liability. Environmental laws and regulations are described more fully beginning on page 18 of this Form 10-K report.
The Company’s liability for remedial obligations includes certain amounts that are based on anticipated regulatory approval for proposed remediation of former refinery waste sites. Although regulatory authorities may require more costly alternatives than the proposed processes, the cost of such potential alternative processes is not expected to exceed the accrued liability by a material amount.
The U.S. Environmental Protection Agency (EPA) currently considers the Company a Potentially Responsible Party (PRP) at two Superfund sites. The potential total cost to all parties to perform necessary remedial work at these sites may be substantial. Based on currently available information, the Company believes that it is a de minimus party as to ultimate responsibility at both Superfund sites. The Company has not recorded a liability for remedial costs on Superfund sites. The Company could be required to bear a pro rata share of costs attributable to nonparticipating PRPs or could be assigned additional responsibility for remediation at the two sites or other Superfund sites. The Company believes that its share of the ultimate costs to clean-up the two Superfund sites will be immaterial and will not have a material adverse effect on its net income, financial condition or liquidity in a future period.
There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.
In December 2000, two of the Company’s Canadian subsidiaries, Murphy Oil Company Ltd. (MOCL) and Murphy Canada Exploration Company (MCEC) as plaintiffs filed an action in the Court of Queen’s Bench of Alberta seeking a constructive trust over oil and gas leasehold rights to Crown lands in British Columbia. The suit alleges that the defendants, The Predator Corporation Ltd. and Predator Energies Partnership (collectively Predator) and Ricks Nova Scotia Co. (Ricks), acquired the lands after first inappropriately obtaining confidential and proprietary data belonging to the Company and its partner. In January 2001, Ricks, representing an undivided 75% interest in the lands in question, settled its portion of the litigation by conveying its interest to the Company and its partner at cost. In 2001, Predator, representing the remaining undivided 25% of the lands in question, filed a counterclaim, as subsequently amended, against MOCL and MCEC and MOCL’s President individually seeking compensatory damages of C$3.61 billion. In September 2004 the court summarily dismissed all claims against MOCL’s president and all but C$356,000,000 of the counterclaim against the Company; however, this dismissal order is currently on appeal. The Company believes that the counterclaim is without merit, that the amount of damages sought is frivolous and the likelihood of a material loss to the Company is remote. It is anticipated that a trial concerning the 25% disputed interest and any remaining issues will commence in 2005. While the litigation is in the discovery stage and no assurance can be given about the outcome, the Company does not believe that the ultimate resolution of this suit will have a material adverse effect on its net income, financial condition or liquidity in a future period. In the unlikely event that Predator were to prevail in its counterclaim in an amount approaching the damages sought, Murphy would incur a material expense in its consolidated statement of income, and would have a material effect on its financial condition and liquidity.
On June 10, 2003, a fire severely damaged the Residual Oil Supercritical Extraction (ROSE) unit at the Company’s Meraux, Louisiana refinery. The ROSE unit recovers feedstock from the heavy fuel oil stream for conversion into gasoline and diesel. Subsequent to the fire, numerous class action lawsuits have been filed seeking damages for area residents. All the lawsuits have been administratively consolidated into a single legal action in St. Bernard Parish, Louisiana, except for one such action which was filed in federal court. Additionally, individual residents of Orleans Parish, Louisiana, have filed an action in that venue. On May 5, 2004, plaintiffs in the consolidated action in St. Bernard Parish amended their petition to include a direct action against certain of the Company’s liability insurers. In responding to this direct action, one of the Company’s insurers, AEGIS, has raised lack of coverage as a defense. The Company believes that this contention lacks merit and has been advised by counsel that the applicable policy does provide coverage for the underlying incident. Because the Company believes that insurance coverage exists for this matter, it does not expect to incur any significant costs associated with the class action lawsuits. Accordingly, the Company continues to believe that the ultimate resolution of the June 2003 ROSE fire litigation will not have a material adverse effect on its net income, financial condition or liquidity in a future period.
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On March 5, 2002, two of the Company’s subsidiaries filed suit against Enron Canada Corp. (Enron) to collect approximately $2.1 million owed to Murphy under canceled gas sales contracts. On May 1, 2002, Enron counterclaimed for approximately $19.8 million allegedly owed by Murphy under those same agreements. Although the lawsuit in the Court of Queen’s Bench, Alberta, is in its early stages and no assurance can be given, the Company does not believe that the Enron counterclaim is meritorious and does not believe that the ultimate resolution of this matter will have a material adverse effect on its net income, financial condition or liquidity in a future period. In the unlikely event that Enron were to prevail in the lawsuit, the Company could incur expense in a future period approximating the amount of the judgment.
Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
OTHER MATTERS – 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, 2004, the Company had contingent liabilities of $8,519,000 under a financial guarantee described in the following paragraph and $55,979,000 on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to these letters of credit because it is believed that the likelihood of having these drawn is remote.
The Company owns a 3.2% interest in the Louisiana Offshore Oil Port (LOOP) that it accounts for at cost. LOOP has issued $361,675,000 in bonds, which mature in varying amounts between 2005 and 2021. The Company is obligated to ship crude oil in quantities sufficient for LOOP to pay certain of its expenses and obligations, including long-term debt secured by a Throughput and Deficiency agreement (T&D), or to make cash payments for which the Company will receive credit for future throughput. No other collateral secures the investee’s obligation or the Company’s guarantee. As of December 31, 2004, it is not probable that the Company will be required to make payments under the guarantee; therefore, no liability has been recorded for the Company’s obligation under the T&D agreement. The Company continues to monitor conditions that are subject to guarantees to identify whether it is probable that a loss has occurred, and it would recognize any such losses under the guarantees should losses become probable.
Note Q – Common Stock Issued and Outstanding
Activity in the number of shares of Common Stock issued and outstanding for the three years ended December 31, 2004 is shown below.
(Number of shares outstanding) | 2004 | 2003 | 2002 | |||||
At beginning of year | 91,870,598 | 91,689,454 | 45,331,080 | |||||
Stock options exercised | 60,000 | 86,500 | 491,700 | |||||
Employee stock purchase and thrift plans | 23,632 | 30,560 | 28,647 | |||||
Restricted stock awards, net of forfeitures | 84,812 | 64,084 | — | |||||
Two-for-one stock split | — | — | 45,838,065 | |||||
All other | (3,665 | ) | — | (38 | ) | |||
At end of year | 92,035,377 | 91,870,598 | 91,689,454 | |||||
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, Malaysia and all other countries; each of these segments derives revenues primarily from the sale of crude oil and natural gas. The refining and marketing segments in North America and the United Kingdom derive revenues mainly from the sale of petroleum products. The Company sells gasoline in the United States and Canada at retail stations built in Wal-Mart parking lots. This business is considered by the Company to be an integrated operation, and therefore, considers it appropriate to combine the U.S. and Canadian businesses into one North American segment. 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 $1,477,873,000, $1,336,600,000 and $1,147,922,000 for the years 2004, 2003 and 2002, 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. 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-28, Certain Long-Lived Assets at December 31 exclude investments, noncurrent receivables, deferred tax assets and intangible assets.
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Segment Information
| Exploration and Production | ||||||||||||||||||||
(Millions of dollars) | U.S. | Canada | U.K. | Ecuador | Malaysia | Other | Total | |||||||||||||
Year ended December 31, 2004 | ||||||||||||||||||||
Segment income (loss) from continuing operations | $ | 159.5 | 232.2 | 87.1 | 6.6 | 38.3 | (11.4 | ) | 512.3 | |||||||||||
Revenues from external customers | 482.8 | 543.9 | 197.4 | 30.8 | 167.2 | 3.4 | 1,425.5 | |||||||||||||
Intersegment revenues | — | 62.8 | — | — | — | — | 62.8 | |||||||||||||
Interest income | — | — | — | — | — | — | — | |||||||||||||
Interest expense, net of capitalization | — | — | — | — | — | — | — | |||||||||||||
Income tax expense | 78.6 | 100.8 | 55.0 | 4.4 | 8.8 | 1.8 | 249.4 | |||||||||||||
Significant noncash charges (credits) | ||||||||||||||||||||
Depreciation, depletion, amortization | 66.9 | 111.6 | 28.0 | 5.3 | 29.6 | .1 | 241.5 | |||||||||||||
Accretion of asset retirement obligations | 3.7 | 3.3 | 2.3 | — | .2 | .4 | 9.9 | |||||||||||||
Provisions for major repairs | — | 6.2 | — | — | — | — | 6.2 | |||||||||||||
Amortization of undeveloped leases | 12.8 | 2.7 | — | — | — | .9 | 16.4 | |||||||||||||
Deferred and noncurrent income taxes | 60.6 | 9.7 | 8.5 | — | (18.5 | ) | (14.5 | ) | 45.8 | |||||||||||
Additions to property, plant, equipment | 144.3 | 320.7 | 3.0 | 12.5 | 197.5 | 13.3 | 691.3 | |||||||||||||
Total assets at year-end | 866.3 | 1,365.4 | 190.2 | 131.3 | 486.7 | 29.3 | 3,069.2 | |||||||||||||
Year ended December 31, 2003 | ||||||||||||||||||||
Segment income (loss) from continuing operations | $ | 23.3 | 166.2 | 95.3 | 16.7 | 10.7 | (8.8 | ) | 303.4 | |||||||||||
Revenues from external customers | 196.7 | 406.3 | 221.6 | 41.9 | 77.7 | 4.2 | 948.4 | |||||||||||||
Intersegment revenues | — | 50.0 | — | — | — | — | 50.0 | |||||||||||||
Interest income | — | — | — | — | — | — | — | |||||||||||||
Interest expense, net of capitalization | — | — | — | — | — | — | — | |||||||||||||
Income tax expense (benefit) | 13.2 | 59.9 | 59.8 | .6 | 3.7 | .7 | 137.9 | |||||||||||||
Significant noncash charges (credits) | ||||||||||||||||||||
Depreciation, depletion, amortization | 36.7 | 103.1 | 32.6 | 7.5 | 18.5 | .2 | 198.6 | |||||||||||||
Impairment of long-lived assets | 3.0 | — | — | — | — | — | 3.0 | |||||||||||||
Accretion of asset retirement obligations | 3.3 | 2.9 | 2.9 | — | .3 | .3 | 9.7 | |||||||||||||
Provisions for major repairs | — | 6.5 | — | — | — | — | 6.5 | |||||||||||||
Amortization of undeveloped leases | 11.5 | 3.1 | .1 | — | — | — | 14.7 | |||||||||||||
Deferred and noncurrent income taxes | 13.4 | (4.9 | ) | 24.8 | — | (7.0 | ) | 2.2 | 28.5 | |||||||||||
Additions to property, plant, equipment | 229.9 | 157.5 | 24.5 | 27.0 | 152.8 | — | 591.7 | |||||||||||||
Total assets at year-end | 742.6 | 1,527.1 | 211.4 | 105.5 | 284.0 | 17.9 | 2,888.5 | |||||||||||||
Year ended December 31, 2002 | ||||||||||||||||||||
Segment income (loss) from continuing operations | $ | (11.8 | ) | 146.8 | 49.6 | 12.0 | (43.0 | ) | (2.8 | ) | 150.8 | |||||||||
Revenues from external customers | 155.0 | 339.7 | 170.6 | 30.7 | — | 2.3 | 698.3 | |||||||||||||
Intersegment revenues | 3.3 | 56.2 | — | — | — | — | 59.5 | |||||||||||||
Interest income | — | — | — | — | — | — | — | |||||||||||||
Interest expense, net of capitalization | — | — | — | — | — | — | — | |||||||||||||
Income tax expense (benefit) | (20.9 | ) | 59.9 | 42.3 | — | — | (.9 | ) | 80.4 | |||||||||||
Significant noncash charges (credits) | ||||||||||||||||||||
Depreciation, depletion, amortization | 34.1 | 68.4 | 35.7 | 5.3 | .9 | .3 | 144.7 | |||||||||||||
Impairment of long-lived assets | 31.6 | — | — | — | — | — | 31.6 | |||||||||||||
Provisions for major repairs | — | 5.5 | — | — | — | — | 5.5 | |||||||||||||
Amortization of undeveloped leases | 10.5 | 3.0 | — | — | — | — | 13.5 | |||||||||||||
Deferred and noncurrent income taxes | (18.7 | ) | 3.6 | 6.1 | — | — | .6 | (8.4 | ) | |||||||||||
Additions to property, plant, equipment | 169.2 | 123.5 | 36.0 | 14.9 | 85.0 | — | 428.6 | |||||||||||||
Total assets at year-end | 661.8 | 1,269.9 | 243.7 | 82.0 | 122.1 | 7.9 | 2,387.4 | |||||||||||||
Geographic Information
| Certain Long-Lived Assets at December 31 | |||||||||||||||
(Millions of dollars) | U.S. | Canada | U.K. | Ecuador | �� | Malaysia | Other | Total | |||||||
2004 | $ | 1,638.2 | 1,260.4 | 277.0 | 90.6 | 406.5 | 21.5 | 3,694.2 | |||||||
2003 | 1,514.9 | 1,386.8 | 295.6 | 89.9 | 243.3 | 7.8 | 3,538.3 | ||||||||
2002 | 1,302.2 | 1,116.8 | 295.0 | 70.9 | 101.8 | 6.3 | 2,893.0 | ||||||||
F-28
Table of Contents
Segment Information (Continued)
| Refining and Marketing | Corp. & Other | Consolidated | |||||||||||||
(Millions of dollars) | North America | U.K. | Total | ||||||||||||
Year ended December 31, 2004 | |||||||||||||||
Segment income (loss) from continuing operations | $ | 53.4 | 28.5 | 81.9 | (97.8 | ) | 496.4 | ||||||||
Revenues from external customers | 6,264.9 | 678.3 | 6,943.2 | (8.9 | ) | 8,359.8 | |||||||||
Intersegment revenues | — | — | — | — | 62.8 | ||||||||||
Interest income | — | — | — | 17.7 | 17.7 | ||||||||||
Interest expense, net of capitalization | — | — | — | 34.1 | 34.1 | ||||||||||
Income tax expense | 37.4 | 14.4 | 51.8 | 7.3 | 308.5 | ||||||||||
Significant noncash charges (credits) | |||||||||||||||
Depreciation, depletion, amortization | 66.7 | 10.6 | 77.3 | 2.6 | 321.4 | ||||||||||
Accretion of asset retirement obligations | .1 | — | .1 | — | 10.0 | ||||||||||
Provisions for major repairs | 20.0 | 3.9 | 23.9 | .1 | 30.2 | ||||||||||
Amortization of undeveloped leases | — | — | — | — | 16.4 | ||||||||||
Deferred and noncurrent income taxes | 30.7 | (1.5 | ) | 29.2 | 32.6 | 107.6 | |||||||||
Additions to property, plant, equipment | 123.7 | 11.0 | 134.7 | 1.5 | 827.5 | ||||||||||
Total assets at year-end | 1,467.2 | 310.8 | 1,778.0 | 611.0 | 5,458.2 | ||||||||||
Year ended December 31, 2003 | |||||||||||||||
Segment income (loss) from continuing operations | $ | (21.2 | ) | 10.0 | (11.2 | ) | (13.8 | ) | 278.4 | ||||||
Revenues from external customers | 3,722.4 | 483.8 | 4,206.2 | 10.0 | 5,164.6 | ||||||||||
Intersegment revenues | — | — | — | — | 50.0 | ||||||||||
Interest income | — | — | — | 4.4 | 4.4 | ||||||||||
Interest expense, net of capitalization | — | — | — | 20.5 | 20.5 | ||||||||||
Income tax expense (benefit) | (11.9 | ) | 5.8 | (6.1 | ) | (36.0 | ) | 95.8 | |||||||
Significant noncash charges (credits) | |||||||||||||||
Depreciation, depletion, amortization | 49.4 | 8.2 | 57.6 | 2.7 | 258.9 | ||||||||||
Impairment of long-lived assets | 5.3 | — | 5.3 | — | 8.3 | ||||||||||
Accretion of asset retirement obligations | — | — | — | — | 9.7 | ||||||||||
Provisions for major repairs | 18.5 | 3.4 | 21.9 | .1 | 28.5 | ||||||||||
Amortization of undeveloped leases | — | — | — | — | 14.7 | ||||||||||
Deferred and noncurrent income taxes | (13.3 | ) | (.6 | ) | (13.9 | ) | (10.4 | ) | 4.2 | ||||||
Additions to property, plant, equipment | 205.8 | 9.6 | 215.4 | 1.1 | 808.2 | ||||||||||
Total assets at year-end | 1,254.1 | 253.3 | 1,507.4 | 316.7 | 4,712.6 | ||||||||||
Year ended December 31, 2002 | |||||||||||||||
Segment income (loss) from continuing operations | $ | (39.2 | ) | (.7 | ) | (39.9 | ) | (23.6 | ) | 87.3 | |||||
Revenues from external customers | 2,688.7 | 404.5 | 3,093.2 | 5.4 | 3,796.9 | ||||||||||
Intersegment revenues | — | — | — | — | 59.5 | ||||||||||
Interest income | — | — | — | 5.4 | 5.4 | ||||||||||
Interest expense, net of capitalization | — | — | — | 27.0 | 27.0 | ||||||||||
Income tax expense (benefit) | (20.7 | ) | 1.5 | (19.2 | ) | (26.9 | ) | 34.3 | |||||||
Significant noncash charges (credits) | |||||||||||||||
Depreciation, depletion, amortization | 43.4 | 6.7 | 50.1 | 2.7 | 197.5 | ||||||||||
Impairment of long-lived assets | — | — | — | — | 31.6 | ||||||||||
Provisions for major repairs | 16.7 | 2.7 | 19.4 | .1 | 25.0 | ||||||||||
Amortization of undeveloped leases | — | — | — | — | 13.5 | ||||||||||
Deferred and noncurrent income taxes | 13.4 | (.5 | ) | 12.9 | (2.6 | ) | 1.9 | ||||||||
Additions to property, plant, equipment | 230.4 | 4.3 | 234.7 | 1.1 | 664.4 | ||||||||||
Total assets at year-end | 996.6 | 211.6 | 1,208.2 | 290.2 | 3,885.8 | ||||||||||
Geographic Information
| Revenues from External Customers for the Year | |||||||||||||||
(Millions of dollars) | U.S. | U.K. | Canada | Ecuador | Malaysia | Other | Total | ||||||||
2004 | $ | 6,713.7 | 872.1 | 572.6 | 30.8 | 167.2 | 3.4 | 8,359.8 | |||||||
2003 | 3,883.4 | 706.5 | 450.9 | 41.9 | 77.7 | 4.2 | 5,164.6 | ||||||||
2002 | 2,843.4 | 578.0 | 529.9 | 30.7 | — | 2.3 | 3,984.3 | ||||||||
F-29
Table of Contents
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, natural gas and synthetic oil 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. Estimated net proved oil reserves shown in Schedule 1 include natural gas liquids.
Oil reserves in Ecuador are derived from a participation contract covering Block 16 in the Amazon region. Oil reserves associated with the participation contract in Ecuador totaled 17.3 million barrels at December 31, 2004. Oil reserves in Malaysia are associated with production sharing contracts for Blocks SK 309 and K. Malaysia reserves include oil to be received for both cost recovery and profit provisions under the contracts. Oil reserves associated with the production sharing contracts in Malaysia totaled 54 million barrels at December 31, 2004.
The Company has no proved reserves attributable to investees accounted for by the equity method.
Synthetic oil reserves in Canada, shown in a separate table following the natural gas reserve table at Schedule 2, are attributable to Murphy’s 5% share, after deducting estimated net profit royalty, of the Syncrude project and include currently producing leases. Additional reserves will be added as development progresses.
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.
SCHEDULE 5 – 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. SFAS No. 69 requires that oil and natural gas prices as of the last business day of the year be used for calculation of the standardized measure of discounted future net cash flows. The average year-end 2004 crude oil prices were $33.99 per barrel for the United States, $33.22 for Canadian light, $12.44 for Canadian heavy, $38.43 for Canadian offshore, $38.26 for the United Kingdom, $23.25 for Ecuador and $39.27 for Malaysia. Average year-end 2004 natural gas prices were $6.71 per MCF for the United States, $5.69 for Canada and $5.57 for the United Kingdom.
Schedule 5 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, 2004.
F-30
Table of Contents
Schedule 1 – Estimated Net Proved Oil Reserves
(Millions of barrels) | United States1 | Canada2 | United Kingdom | Ecuador | Malaysia | Total | ||||||||||||
Proved | ||||||||||||||||||
December 31, 2001 | 88.6 | 60.5 | 44.1 | 38.7 | 15.0 | 246.9 | ||||||||||||
Revisions of previous estimates | (6.5 | ) | 6.6 | 3.7 | (4.1 | ) | .3 | — | ||||||||||
Extensions and discoveries | 3.8 | 8.4 | 2.0 | — | — | 14.2 | ||||||||||||
Production | (1.9 | ) | (13.5 | ) | (6.7 | ) | (1.7 | ) | — | (23.8 | ) | |||||||
Sales | (3.4 | ) | (2.3 | ) | — | — | — | (5.7 | ) | |||||||||
December 31, 2002 | 80.6 | 59.7 | 43.1 | 32.9 | 15.3 | 231.6 | ||||||||||||
Revisions of previous estimates | (1.7 | ) | 8.0 | .4 | (.6 | ) | .5 | 6.6 | ||||||||||
Extensions and discoveries | 1.0 | 10.2 | — | — | 3.8 | 15.0 | ||||||||||||
Production | (1.7 | ) | (15.0 | ) | (5.4 | ) | (1.9 | ) | (2.7 | ) | (26.7 | ) | ||||||
Sales | — | (2.9 | ) | (9.8 | ) | — | — | (12.7 | ) | |||||||||
December 31, 2003 | 78.2 | 60.0 | 28.3 | 30.4 | 16.9 | 213.8 | ||||||||||||
Revisions of previous estimates | (7.4 | ) | (6.5 | ) | .4 | (10.3 | ) | (1.1 | ) | (24.9 | ) | |||||||
Purchases | — | 7.1 | — | — | — | 7.1 | ||||||||||||
Extensions and discoveries | 2.4 | 13.1 | .6 | — | 42.6 | 58.7 | ||||||||||||
Production | (7.1 | ) | (12.8 | ) | (4.0 | ) | (2.8 | ) | (4.4 | ) | (31.1 | ) | ||||||
Sale of properties | (.1 | ) | (19.7 | ) | (1.0 | ) | — | — | (20.8 | ) | ||||||||
December 31, 2004 | 66.0 | 41.2 | 24.3 | 17.3 | 54.0 | 202.8 | ||||||||||||
Proved Developed | ||||||||||||||||||
December 31, 2001 | 8.8 | 37.9 | 33.3 | 21.3 | — | 101.3 | ||||||||||||
December 31, 2002 | 5.2 | 47.1 | 36.2 | 19.0 | — | 107.5 | ||||||||||||
December 31, 2003 | 23.9 | 47.7 | 24.4 | 17.7 | 11.8 | 125.5 | ||||||||||||
December 31, 2004 | 31.3 | 32.5 | 19.8 | 7.9 | 12.4 | 103.9 |
| 1 | Includes net proved oil reserves related to discontinued operations of 2.0 million barrels at December 31, 2001. |
| 2 | Includes net proved oil reserves related to discontinued operations of 20.8 million barrels at December 31, 2003, 22.5 million barrels at December 31, 2002, and 20.6 million barrels at December 31, 2001. |
F-31
Table of Contents
Schedule 2 – Estimated Net Proved Natural Gas Reserves
(Billions of cubic feet) | United States1 | Canada2 | United Kingdom | Total | ||||||||
Proved | ||||||||||||
December 31, 2001 | 395.7 | 309.5 | 34.9 | 740.1 | ||||||||
Revisions of previous estimates | (84.2 | ) | (7.5 | ) | (1.5 | ) | (93.2 | ) | ||||
Purchases | — | .4 | — | .4 | ||||||||
Extensions and discoveries | 3.8 | 12.7 | — | 16.5 | ||||||||
Production | (33.6 | ) | (72.1 | ) | (2.6 | ) | (108.3 | ) | ||||
Sales | (13.2 | ) | (17.1 | ) | — | (30.3 | ) | |||||
December 31, 2002 | 268.5 | 225.9 | 30.8 | 525.2 | ||||||||
Revisions of previous estimates | (4.5 | ) | (8.6 | ) | .1 | (13.0 | ) | |||||
Extensions and discoveries | 14.7 | 16.8 | — | 31.5 | ||||||||
Production | (30.0 | ) | (45.1 | ) | (3.5 | ) | (78.6 | ) | ||||
Sales | — | (15.8 | ) | — | (15.8 | ) | ||||||
December 31, 2003 | 248.7 | 173.2 | 27.4 | 449.3 | ||||||||
Revisions of previous estimates | 8.1 | 3.5 | — | 11.6 | ||||||||
Extensions and discoveries | 4.6 | 4.0 | — | 8.6 | ||||||||
Production | (32.4 | ) | (16.4 | ) | (2.5 | ) | (51.3 | ) | ||||
Sale of properties | (8.5 | ) | (140.7 | ) | (.2 | ) | (149.4 | ) | ||||
December 31, 2004 | 220.5 | 23.6 | 24.7 | 268.8 | ||||||||
Proved Developed | ||||||||||||
December 31, 2001 | 189.6 | 277.5 | 34.1 | 501.2 | ||||||||
December 31, 2002 | 139.7 | 205.6 | 30.1 | 375.4 | ||||||||
December 31, 2003 | 150.5 | 156.0 | 26.6 | 333.1 | ||||||||
December 31, 2004 | 136.6 | 22.2 | 24.0 | 182.8 |
| 1 | Includes net proved natural gas reserves related to discontinued operations of 8.1 billion cubic feet at December 31, 2001. |
| 2 | Includes net proved natural gas reserves related to discontinued operations of 150.5 billion cubic feet at December 31, 2003, 195.5 billion cubic feet at December 31, 2002, and 278.4 billion cubic feet at December 31, 2001. |
Information on Proved Reserves for Canadian Synthetic Oil Operation Not Included in Net Proved Oil Reserves
The Company has a 5% interest in Syncrude, the world’s largest tar sands synthetic oil production project located in Alberta, Canada. In addition to conventional liquids and natural gas proved reserves, Murphy has significant proved synthetic oil reserves associated with Syncrude that are shown in the table below. For internal management purposes, Murphy views these reserves and ongoing production and development as an integral part of its total Exploration and Production operations. However, the U.S. Securities and Exchange Commission’s regulations define Syncrude as a mining operation, and therefore, do not permit these associated proved reserves to be included as a part of conventional oil and natural gas reserves. These reserves are also not included in the Company’s schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, which can be found on page F-36.
Synthetic Oil Proved Reserves
(Millions of barrels) | ||
December 31, 2001 | 131.0 | |
December 31, 2002 | 136.2 | |
December 31, 2003 | 136.8 | |
December 31, 2004 | 138.0 |
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Table of Contents
Schedule 3 – Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
(Millions of dollars) | United States1 | Canada2,3 | United Kingdom | Ecuador | Malaysia | Other | Total | ||||||||||
Year Ended December 31, 2004 | |||||||||||||||||
Property acquisition costs | |||||||||||||||||
Unproved | $ | 9.7 | 54.8 | — | — | — | 6.1 | 70.6 | |||||||||
Proved | — | 67.3 | — | — | — | — | 67.3 | ||||||||||
Total acquisition costs | 9.7 | 122.1 | — | — | — | 6.1 | 137.9 | ||||||||||
Exploration costs | 95.1 | 10.9 | 1.0 | — | 151.5 | 9.6 | 268.1 | ||||||||||
Development costs | 96.5 | 101.9 | 3.0 | 12.5 | 108.7 | — | 322.6 | ||||||||||
Total capital expenditures | 201.3 | 234.9 | 4.0 | 12.5 | 260.2 | 15.7 | 728.6 | ||||||||||
Asset retirement costs | 12.4 | 7.2 | 1.9 | — | (2.8 | ) | — | 18.7 | |||||||||
Charged to expense | |||||||||||||||||
Dry hole expense | 41.3 | 21.4 | .7 | — | 47.4 | .1 | 110.9 | ||||||||||
Geophysical and other costs | 15.7 | 3.4 | .3 | — | 15.3 | 2.3 | 37.0 | ||||||||||
Total charged to expense | 57.0 | 24.8 | 1.0 | — | 62.7 | 2.4 | 147.9 | ||||||||||
Property additions | $ | 156.7 | 217.3 | 4.9 | 12.5 | 194.7 | 13.3 | 599.4 | |||||||||
Year Ended December 31, 2003 | |||||||||||||||||
Property acquisition costs | |||||||||||||||||
Unproved | $ | 19.9 | 2.9 | — | — | — | — | 22.8 | |||||||||
Proved | — | — | — | — | — | — | — | ||||||||||
Total acquisition costs | 19.9 | 2.9 | — | — | — | — | 22.8 | ||||||||||
Exploration costs | 72.5 | 23.9 | .3 | — | 68.9 | 5.1 | 170.7 | ||||||||||
Development costs | 189.4 | 45.9 | 24.5 | 27.0 | 115.5 | — | 402.3 | ||||||||||
Total capital expenditures | 281.8 | 72.7 | 24.8 | 27.0 | 184.4 | 5.1 | 595.8 | ||||||||||
Asset retirement costs | 13.6 | 3.9 | — | — | 5.7 | — | 23.2 | ||||||||||
Charged to expense | |||||||||||||||||
Dry hole expense | 36.4 | 2.8 | (.1 | ) | — | 17.6 | 3.9 | 60.6 | |||||||||
Geophysical and other costs | 15.5 | 6.2 | .4 | — | 14.0 | 1.2 | 37.3 | ||||||||||
Total charged to expense | 51.9 | 9.0 | .3 | — | 31.6 | 5.1 | 97.9 | ||||||||||
Property additions | $ | 243.5 | 67.6 | 24.5 | 27.0 | 158.5 | — | 521.1 | |||||||||
Year Ended December 31, 2002 | |||||||||||||||||
Property acquisition costs | |||||||||||||||||
Unproved | $ | 8.4 | 7.2 | — | — | — | — | 15.6 | |||||||||
Proved | — | .6 | — | — | — | — | .6 | ||||||||||
Total acquisition costs | 8.4 | 7.8 | — | — | — | — | 16.2 | ||||||||||
Exploration costs | 56.7 | 25.0 | 3.8 | — | 102.3 | .2 | 188.0 | ||||||||||
Development costs | 156.7 | 40.9 | 36.0 | 14.9 | 24.8 | — | 273.3 | ||||||||||
Total capital expenditures | 221.8 | 73.7 | 39.8 | 14.9 | 127.1 | .2 | 477.5 | ||||||||||
Charged to expense | |||||||||||||||||
Dry hole expense | 39.8 | 8.9 | 3.1 | — | 37.9 | .1 | 89.8 | ||||||||||
Geophysical and other costs | 12.8 | 2.8 | .7 | — | 4.2 | .1 | 20.6 | ||||||||||
Total charged to expense | 52.6 | 11.7 | 3.8 | — | 42.1 | .2 | 110.4 | ||||||||||
Property additions4 | $ | 169.2 | 62.0 | 36.0 | 14.9 | 85.0 | — | 367.1 | |||||||||
| 1 | Excludes property additions of $.5 million in 2002 related to discontinued operations. |
| 2 | Excludes property additions for the Company’s 5% interest in synthetic oil operations in Canada, which were $110.6 million in 2004, $93.8 million in 2003 and $61.5 million in 2002. |
| 3 | Excludes property additions of $4.6 million in 2004, $49.3 million in 2003, and $68.3 million in 2002 related to discontinued operations. |
| 4 | Excludes pro forma total asset retirement costs, assuming SFAS No. 143 had been applied retroactively, of $8.3 million. |
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Table of Contents
Schedule 4 – Results of Operations for Oil and Gas Producing Activities
(Millions of dollars) | United States | Canada | United Kingdom | Ecuador | Malaysia | Other | Subtotal | Synthetic Oil – Canada | Total | ||||||||||||
Year Ended December 31, 2004 | |||||||||||||||||||||
Revenues | |||||||||||||||||||||
Crude oil and natural gas liquids | |||||||||||||||||||||
Transfers to consolidated operations | $ | — | 31.5 | — | — | — | — | 31.5 | 31.3 | 62.8 | |||||||||||
Sales to unaffiliated enterprises | 248.4 | 371.8 | 146.8 | 30.8 | 167.2 | — | 965.0 | 142.9 | 1,107.9 | ||||||||||||
Natural gas | |||||||||||||||||||||
Transfers to consolidated companies | — | — | — | — | — | — | — | — | — | ||||||||||||
Sales to unaffiliated enterprises | 207.6 | 28.7 | 11.4 | — | — | — | 247.7 | — | 247.7 | ||||||||||||
Total oil and gas revenues | 456.0 | 432.0 | 158.2 | 30.8 | 167.2 | — | 1,244.2 | 174.2 | 1,418.4 | ||||||||||||
Other operating revenues | 26.8 | .5 | 39.2 | — | — | 3.4 | 69.9 | — | 69.9 | ||||||||||||
Total revenues | 482.8 | 432.5 | 197.4 | 30.8 | 167.2 | 3.4 | 1,314.1 | 174.2 | 1,488.3 | ||||||||||||
Costs and expenses | |||||||||||||||||||||
Production expenses | 76.3 | 39.4 | 18.8 | 13.9 | 22.7 | — | 171.1 | 77.9 | 249.0 | ||||||||||||
Storm damage and estimated retrospective insurance costs | 8.7 | 2.9 | 2.4 | — | .1 | — | 14.1 | 1.1 | 15.2 | ||||||||||||
Exploration costs charged to expense | 57.0 | 24.8 | 1.0 | — | 62.7 | 2.4 | 147.9 | — | 147.9 | ||||||||||||
Undeveloped lease amortization | 12.8 | 2.7 | — | — | — | .9 | 16.4 | — | 16.4 | ||||||||||||
Depreciation, depletion and amortization | 66.9 | 100.8 | 28.0 | 5.3 | 29.6 | .1 | 230.7 | 10.8 | 241.5 | ||||||||||||
Accretion of asset retirement obligations | 3.7 | 2.9 | 2.3 | — | .2 | .4 | 9.5 | .4 | 9.9 | ||||||||||||
Selling and general expenses | 19.3 | 9.4 | 2.8 | .6 | 4.8 | 9.2 | 46.1 | .6 | 46.7 | ||||||||||||
Total costs and expenses | 244.7 | 182.9 | 55.3 | 19.8 | 120.1 | 13.0 | 635.8 | 90.8 | 726.6 | ||||||||||||
| 238.1 | 249.6 | 142.1 | 11.0 | 47.1 | (9.6 | ) | 678.3 | 83.4 | 761.7 | ||||||||||||
Income tax expense | 78.6 | 76.4 | 55.0 | 4.4 | 8.8 | 1.8 | 225.0 | 24.4 | 249.4 | ||||||||||||
Results of operations* | $ | 159.5 | 173.2 | 87.1 | 6.6 | 38.3 | (11.4 | ) | 453.3 | 59.0 | 512.3 | ||||||||||
Year Ended December 31, 2003 | |||||||||||||||||||||
Revenues | |||||||||||||||||||||
Crude oil and natural gas liquids | |||||||||||||||||||||
Transfers to consolidated operations | $ | — | 33.0 | — | — | — | — | 33.0 | 17.0 | 50.0 | |||||||||||
Sales to unaffiliated enterprises | 39.2 | 281.8 | 158.6 | 41.9 | 77.7 | — | 599.2 | 78.7 | 677.9 | ||||||||||||
Natural gas | |||||||||||||||||||||
Transfers to consolidated operations | — | — | — | — | — | — | — | — | — | ||||||||||||
Sales to unaffiliated enterprises | 158.3 | 34.9 | 12.2 | — | — | — | 205.4 | — | 205.4 | ||||||||||||
Total oil and gas revenues | 197.5 | 349.7 | 170.8 | 41.9 | 77.7 | — | 837.6 | 95.7 | 933.3 | ||||||||||||
Other operating revenues | (.8 | ) | 10.9 | 50.8 | — | — | 4.2 | 65.1 | — | 65.1 | |||||||||||
Total revenues | 196.7 | 360.6 | 221.6 | 41.9 | 77.7 | 4.2 | 902.7 | 95.7 | 998.4 | ||||||||||||
Costs and expenses | |||||||||||||||||||||
Production expenses | 36.8 | 36.4 | 27.9 | 16.5 | 9.1 | — | 126.7 | 62.9 | 189.6 | ||||||||||||
Exploration costs charged to expense | 51.9 | 9.0 | .3 | — | 31.6 | 5.1 | 97.9 | — | 97.9 | ||||||||||||
Undeveloped lease amortization | 11.5 | 3.1 | .1 | — | — | — | 14.7 | — | 14.7 | ||||||||||||
Depreciation, depletion and amortization | 36.7 | 94.0 | 32.6 | 7.5 | 18.5 | .2 | 189.5 | 9.1 | 198.6 | ||||||||||||
Impairment of properties | 3.0 | — | — | — | — | — | 3.0 | — | 3.0 | ||||||||||||
Accretion of asset retirement obligations | 3.3 | 2.5 | 2.9 | — | .3 | .3 | 9.3 | .4 | 9.7 | ||||||||||||
Selling and general expenses | 17.0 | 12.2 | 2.7 | .6 | 3.8 | 6.7 | 43.0 | .6 | 43.6 | ||||||||||||
Total costs and expenses | 160.2 | 157.2 | 66.5 | 24.6 | 63.3 | 12.3 | 484.1 | 73.0 | 557.1 | ||||||||||||
| 36.5 | 203.4 | 155.1 | 17.3 | 14.4 | (8.1 | ) | 418.6 | 22.7 | 441.3 | ||||||||||||
Income tax expense | 13.2 | 55.6 | 59.8 | .6 | 3.7 | .7 | 133.6 | 4.3 | 137.9 | ||||||||||||
Results of operations* | $ | 23.3 | 147.8 | 95.3 | 16.7 | 10.7 | (8.8 | ) | 285.0 | 18.4 | 303.4 | ||||||||||
| * | Excludes discontinued operations, corporate overhead and interest in 2004 and 2003. Income from discontinued operations was $204.9 million in 2004 and $22.8 million in 2003. |
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Schedule 4 – Results of Operations for Oil and Gas Producing Activities (Contd.)
(Millions of dollars) | United States | Canada | United Kingdom | Ecuador | Malaysia | Other | Subtotal | Synthetic Oil – Canada | Total | |||||||||||||
Year Ended December 31, 2002 | ||||||||||||||||||||||
Revenues | ||||||||||||||||||||||
Crude oil and natural gas liquids | ||||||||||||||||||||||
Transfers to consolidated operations | $ | — | 24.5 | — | — | — | — | 24.5 | 31.7 | 56.2 | ||||||||||||
Sales to unaffiliated enterprises | 30.0 | 230.5 | 163.0 | 30.7 | — | — | 454.2 | 74.6 | 528.8 | |||||||||||||
Natural gas | ||||||||||||||||||||||
Transfers to consolidated operations | 3.3 | — | — | — | — | — | 3.3 | — | 3.3 | |||||||||||||
Sales to unaffiliated enterprises | 108.0 | 33.1 | 7.0 | — | — | — | 148.1 | — | 148.1 | |||||||||||||
Total oil and gas revenues | 141.3 | 288.1 | 170.0 | 30.7 | — | — | 630.1 | 106.3 | 736.4 | |||||||||||||
Other operating revenues | 17.0 | 1.5 | .6 | — | — | 2.3 | 21.4 | — | 21.4 | |||||||||||||
Total revenues | 158.3 | 289.6 | 170.6 | 30.7 | — | 2.3 | 651.5 | 106.3 | 757.8 | |||||||||||||
Costs and expenses | ||||||||||||||||||||||
Production expenses | 43.7 | 48.2 | 35.9 | 12.8 | — | — | 140.6 | 48.7 | 189.3 | |||||||||||||
Storm damage costs | 5.0 | — | — | — | — | — | 5.0 | — | 5.0 | |||||||||||||
Exploration costs charged to expense | 52.6 | 11.7 | 3.8 | — | 42.1 | .2 | 110.4 | — | 110.4 | |||||||||||||
Undeveloped lease amortization | 10.5 | 3.0 | — | — | — | — | 13.5 | — | 13.5 | |||||||||||||
Depreciation, depletion and amortization | 34.1 | 59.6 | 35.7 | 5.3 | .9 | .3 | 135.9 | 8.8 | 144.7 | |||||||||||||
Impairment of properties | 31.6 | — | — | — | — | — | 31.6 | — | 31.6 | |||||||||||||
Selling and general expenses | 13.5 | 8.9 | 3.3 | .6 | — | 5.5 | 31.8 | .3 | 32.1 | |||||||||||||
Total costs and expenses | 191.0 | 131.4 | 78.7 | 18.7 | 43.0 | 6.0 | 468.8 | 57.8 | 526.6 | |||||||||||||
| (32.7 | ) | 158.2 | 91.9 | 12.0 | (43.0 | ) | (3.7 | ) | 182.7 | 48.5 | 231.2 | |||||||||||
Income tax expense (benefit) | (20.9 | ) | 44.3 | 42.3 | — | — | (.9 | ) | 64.8 | 15.6 | 80.4 | |||||||||||
Results of operations* | $ | (11.8 | ) | 113.9 | 49.6 | 12.0 | (43.0 | ) | (2.8 | ) | 117.9 | 32.9 | 150.8 | |||||||||
| * | Excludes discontinued operations, corporate overhead and interest in 2002. Income from discontinued operations was $24.2 million in 2002. Excludes pro forma accretion of asset retirement obligations of $10.3 million in 2002. |
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Schedule 5 – Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
(Millions of dollars) | United States | Canada1,2 | United Kingdom | Ecuador | Malaysia | Total | |||||||||||||
December 31, 2004 | |||||||||||||||||||
Future cash inflows | $ | 3,721.2 | 1,215.2 | 1,119.6 | 401.8 | 2,119.2 | 8,577.0 | ||||||||||||
Future development costs | (194.8 | ) | (31.9 | ) | (34.7 | ) | (39.7 | ) | (625.6 | ) | (926.7 | ) | |||||||
Future production and abandonment costs | (595.7 | ) | (342.0 | ) | (247.9 | ) | (128.7 | ) | (739.4 | ) | (2,053.7 | ) | |||||||
Future income taxes | (862.3 | ) | (252.9 | ) | (352.9 | ) | (42.4 | ) | (312.9 | ) | (1,823.4 | ) | |||||||
Future net cash flows | 2,068.4 | 588.4 | 484.1 | 191.0 | 441.3 | 3,773.2 | |||||||||||||
10% annual discount for estimated timing of cash flows | (485.8 | ) | (75.4 | ) | (173.3 | ) | (45.9 | ) | (210.4 | ) | (990.8 | ) | |||||||
Standardized measure of discounted future net cash flows | $ | 1,582.6 | 513.0 | 310.8 | 145.1 | 230.9 | 2,782.4 | ||||||||||||
December 31, 2003 | |||||||||||||||||||
Future cash inflows | $ | 3,787.5 | 2,239.6 | 948.2 | 685.1 | 544.6 | 8,205.0 | ||||||||||||
Future development costs | (184.2 | ) | (85.4 | ) | (22.7 | ) | (41.4 | ) | (104.1 | ) | (437.8 | ) | |||||||
Future production and abandonment costs | (631.1 | ) | (649.5 | ) | (268.8 | ) | (264.6 | ) | (143.2 | ) | (1,957.2 | ) | |||||||
Future income taxes | (1,001.2 | ) | (419.0 | ) | (265.0 | ) | (116.5 | ) | (129.6 | ) | (1,931.3 | ) | |||||||
Future net cash flows | 1,971.0 | 1,085.7 | 391.7 | 262.6 | 167.7 | 3,878.7 | |||||||||||||
10% annual discount for estimated timing of cash flows | (560.7 | ) | (266.2 | ) | (122.9 | ) | (72.7 | ) | (36.3 | ) | (1,058.8 | ) | |||||||
Standardized measure of discounted future net cash flows | $ | 1,410.3 | 819.5 | 268.8 | 189.9 | 131.4 | 2,819.9 | ||||||||||||
December 31, 2002 | |||||||||||||||||||
Future cash inflows | $ | 3,657.1 | 2,344.2 | 1,374.9 | 690.3 | 468.5 | 8,535.0 | ||||||||||||
Future development costs | (332.0 | ) | (57.0 | ) | (55.2 | ) | (64.5 | ) | (83.6 | ) | (592.3 | ) | |||||||
Future production and abandonment costs | (579.0 | ) | (487.2 | ) | (421.1 | ) | (250.4 | ) | (149.5 | ) | (1,887.2 | ) | |||||||
Future income taxes | (905.7 | ) | (579.7 | ) | (376.8 | ) | (116.7 | ) | (84.6 | ) | (2,063.5 | ) | |||||||
Future net cash flows | 1,840.4 | 1,220.3 | 521.8 | 258.7 | 150.8 | 3,992.0 | |||||||||||||
10% annual discount for estimated timing of cash flows | (633.6 | ) | (291.3 | ) | (160.0 | ) | (88.2 | ) | (38.5 | ) | (1,211.6 | ) | |||||||
Standardized measure of discounted future net cash flows | $ | 1,206.8 | 929.0 | 361.8 | 170.5 | 112.3 | 2,780.4 | ||||||||||||
| 1 | Includes discounted future net cash flows from discontinued operations of $322.2 million and $392.1 million at December 31, 2003 and 2002, respectively. |
| 2 | Excludes discounted future net cash flows from synthetic oil of $708.6 million at December 31, 2004, $451.5 million at December 31, 2003 and $411 million at December 31, 2002. |
Following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown.
(Millions of dollars) | 2004 | 2003 | 2002 | |||||||
Net changes in prices, production costs and development costs | $ | (1.4 | ) | (97.0 | ) | 2,480.2 | ||||
Sales and transfers of oil and gas produced, net of production costs | (1,143.0 | ) | (938.8 | ) | (672.9 | ) | ||||
Net change due to extensions and discoveries | 1,056.5 | 307.7 | 238.8 | |||||||
Net change due to purchases and sales of proved reserves | (272.0 | ) | (196.7 | ) | (150.9 | ) | ||||
Development costs incurred | 310.7 | 426.9 | 304.3 | |||||||
Accretion of discount | 421.1 | 420.4 | 202.5 | |||||||
Revisions of previous quantity estimates | (443.4 | ) | 85.1 | (223.2 | ) | |||||
Net change in income taxes | 34.0 | 31.9 | (824.8 | ) | ||||||
Net increase (decrease) | (37.5 | ) | 39.5 | 1,354.0 | ||||||
Standardized measure at January 1 | 2,819.9 | 2,780.4 | 1,426.4 | |||||||
Standardized measure at December 31 | $ | 2,782.4 | 2,819.9 | 2,780.4 | ||||||
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Schedule 6 – Capitalized Costs Relating to Oil and Gas Producing Activities
(Millions of dollars) | United States | Canada | United Kingdom | Ecuador | Malaysia | Other | Subtotal | Synthetic Oil – Canada | Total | |||||||||||||||||||
December 31, 2004 | ||||||||||||||||||||||||||||
Unproved oil and gas properties | $ | 166.2 | 33.2 | .1 | — | 89.5 | 16.7 | 305.7 | — | 305.7 | ||||||||||||||||||
Proved oil and gas properties | 1,581.4 | 1,105.1 | 368.0 | 282.2 | 353.9 | — | 3,690.6 | 579.2 | 4,269.8 | |||||||||||||||||||
Asset retirement costs | 62.1 | 45.9 | 16.8 | — | 3.5 | 3.4 | 131.7 | 4.4 | 136.1 | |||||||||||||||||||
Gross capitalized costs | 1,809.7 | 1,184.2 | 384.9 | 282.2 | 446.9 | 20.1 | 4,128.0 | 583.6 | 4,711.6 | |||||||||||||||||||
Accumulated depreciation, depletion and amortization | ||||||||||||||||||||||||||||
Unproved oil and gas properties | (34.2 | ) | (8.2 | ) | (.1 | ) | — | — | (4.3 | ) | (46.8 | ) | — | (46.8 | ) | |||||||||||||
Proved oil and gas properties | (1,047.9 | ) | (400.6 | ) | (209.8 | ) | (191.6 | ) | (44.6 | ) | — | (1,894.5 | ) | (89.2 | ) | (1,983.7 | ) | |||||||||||
Asset retirement costs | (34.9 | ) | (17.7 | ) | (8.6 | ) | — | (2.7 | ) | (3.4 | ) | (67.3 | ) | (.4 | ) | (67.7 | ) | |||||||||||
Net capitalized costs | $ | 692.7 | 757.7 | 166.4 | 90.6 | 399.6 | 12.4 | 2,119.4 | 494.0 | 2,613.4 | ||||||||||||||||||
December 31, 2003 | ||||||||||||||||||||||||||||
Unproved oil and gas properties | $ | 125.3 | 120.8 | .1 | — | 154.5 | 3.5 | 404.2 | — | 404.2 | ||||||||||||||||||
Proved oil and gas properties | 1,516.6 | 1,751.9 | 614.1 | 269.7 | 93.7 | — | 4,246.0 | 425.5 | 4,671.5 | |||||||||||||||||||
Asset retirement costs | 50.3 | 65.0 | 29.6 | — | 8.1 | 3.1 | 156.1 | 4.1 | 160.2 | |||||||||||||||||||
Gross capitalized costs | 1,692.2 | 1,937.7 | 643.8 | 269.7 | 256.3 | 6.6 | 4,806.3 | 429.6 | 5,235.9 | |||||||||||||||||||
Accumulated depreciation, depletion and amortization | ||||||||||||||||||||||||||||
Unproved oil and gas properties | (24.6 | ) | (52.0 | ) | (.1 | ) | — | — | (3.5 | ) | (80.2 | ) | — | (80.2 | ) | |||||||||||||
Proved oil and gas properties | (1,018.2 | ) | (833.3 | ) | (429.9 | ) | (179.8 | ) | (16.3 | ) | — | (2,477.5 | ) | (71.8 | ) | (2,549.3 | ) | |||||||||||
Asset retirement costs | (31.4 | ) | (32.0 | ) | (21.8 | ) | — | (1.7 | ) | (3.1 | ) | (90.0 | ) | (.3 | ) | (90.3 | ) | |||||||||||
Net capitalized costs | $ | 618.0 | 1,020.4 | 192.0 | 89.9 | 238.3 | — | 2,158.6 | 357.5 | 2,516.1 | ||||||||||||||||||
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Table of Contents
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED)
(Millions of dollars except per share amounts) | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Year | ||||||||
Year Ended December 31, 2004 | |||||||||||||
Sales and other operating revenues | $ | 1,628.2 | 2,097.0 | 2,262.3 | 2,311.6 | 8,299.1 | |||||||
Income from continuing operations before income taxes | 139.8 | 257.6 | 196.4 | 211.1 | 804.9 | ||||||||
Income from continuing operations | 80.7 | 168.1 | 115.8 | 131.8 | 496.4 | ||||||||
Income from discontinued operations | 17.5 | 181.8 | 2.9 | 2.7 | 204.9 | ||||||||
Net income | 98.2 | 349.9 | 118.7 | 134.5 | 701.3 | ||||||||
Income per Common share – basic | |||||||||||||
Continuing operations | .88 | 1.82 | 1.26 | 1.43 | 5.39 | ||||||||
Discontinued operations | .19 | 1.98 | .03 | .03 | 2.23 | ||||||||
Net income | 1.07 | 3.80 | 1.29 | 1.46 | 7.62 | ||||||||
Income per Common share – diluted | |||||||||||||
Continuing operations | .86 | 1.80 | 1.24 | 1.41 | 5.31 | ||||||||
Discontinued operations | .19 | 1.95 | .03 | .03 | 2.20 | ||||||||
Net income | 1.05 | 3.75 | 1.27 | 1.44 | 7.51 | ||||||||
Cash dividend per Common share | .20 | .20 | .225 | .225 | .85 | ||||||||
Market price of Common Stock1 | |||||||||||||
High | 66.99 | 73.70 | 86.77 | 86.30 | 86.30 | ||||||||
Low | 58.08 | 62.91 | 70.14 | 77.56 | 58.08 | ||||||||
Year Ended December 31, 20032 | |||||||||||||
Sales and other operating revenues | $ | 1,257.2 | 1,176.2 | 1,251.4 | 1,409.7 | 5,094.5 | |||||||
Income from continuing operations before income taxes | 102.2 | 111.0 | 85.3 | 75.7 | 374.2 | ||||||||
Income from continuing operations | 82.9 | 72.3 | 66.8 | 56.4 | 278.4 | ||||||||
Income from discontinued operations | 11.2 | 7.4 | 1.9 | 2.3 | 22.8 | ||||||||
Income before cumulative effect of accounting change | 94.1 | 79.7 | 68.7 | 58.7 | 301.2 | ||||||||
Cumulative effect of accounting change | (7.0 | ) | — | — | — | (7.0 | ) | ||||||
Net income | 87.1 | 79.7 | 68.7 | 58.7 | 294.2 | ||||||||
Income per Common share – basic | |||||||||||||
Continuing operations | .91 | .79 | .73 | .61 | 3.03 | ||||||||
Discontinued operations | .12 | .08 | .02 | .03 | .25 | ||||||||
Cumulative effect of accounting change | (.08 | ) | — | — | — | (.08 | ) | ||||||
Net income | .95 | .87 | .75 | .64 | 3.20 | ||||||||
Income per Common share – diluted | |||||||||||||
Continuing operations | .90 | .78 | .72 | .61 | 3.00 | ||||||||
Discontinued operations | .12 | .08 | .02 | .02 | .25 | ||||||||
Cumulative effect of accounting change | (.08 | ) | — | — | — | (.08 | ) | ||||||
Net income | .94 | .86 | .74 | .63 | 3.17 | ||||||||
Cash dividend per Common share | .20 | .20 | .20 | .20 | .80 | ||||||||
Market price of Common Stock1 | |||||||||||||
High | 45.24 | 53.34 | 59.00 | 68.02 | 68.02 | ||||||||
Low | 38.84 | 40.87 | 47.58 | 57.52 | 38.84 | ||||||||
| 1 | Prices are as quoted on the New York Stock Exchange. |
| 2 | Reclassified to conform to 2004 presentation. |
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Table of Contents
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SCHEDULE II – VALUATION ACCOUNTS AND RESERVES
(Millions of dollars) | Balance at January 1 | Charged (Credited) to Expense | Deductions | Other1 | Balance at December 31 | |||||||||
2004 | ||||||||||||||
Deducted from asset accounts: | ||||||||||||||
Allowance for doubtful accounts | $ | 14.3 | 2.2 | (2.8 | ) | .3 | 14.0 | |||||||
Deferred tax asset valuation allowance | 68.1 | (6.8 | )2 | — | — | 61.3 | ||||||||
Included in liabilities: | ||||||||||||||
Accrued major repair costs | 20.5 | 30.2 | (8.0 | ) | 1.5 | 44.2 | ||||||||
2003 | ||||||||||||||
Deducted from asset accounts: | ||||||||||||||
Allowance for doubtful accounts | $ | 9.3 | 6.1 | (1.5 | ) | .4 | 14.3 | |||||||
Deferred tax asset valuation allowance | 89.6 | (21.5 | )2 | — | — | 68.1 | ||||||||
Included in liabilities: | ||||||||||||||
Accrued major repair costs | 53.0 | 28.5 | (61.9 | ) | .9 | 20.5 | ||||||||
2002 | ||||||||||||||
Deducted from asset accounts: | ||||||||||||||
Allowance for doubtful accounts | $ | 11.3 | .8 | (2.7 | ) | (.1 | ) | 9.3 | ||||||
Deferred tax asset valuation allowance | 67.7 | 21.9 | — | — | 89.6 | |||||||||
Included in liabilities: | ||||||||||||||
Accrued major repair costs | 44.6 | 25.0 | (17.0 | ) | .4 | 53.0 | ||||||||
| 1 | Amounts represent changes in foreign currency exchange rates. |
| 2 | Includes recognition of deferred income tax benefits of $31.9 million in 2004 for Block K and $11.4 million in 2003 for Blocks SK 309 and 311 in Malaysia. |
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Table of Contents
GLOSSARY OF TERMS
bitumen or oil sands tar-like hydrocarbon-bearing substance that occurs naturally in certain areas at the Earth’s surface or at relatively shallow depths
clean fuels low-sulfur content gasoline and diesel products
deepwater offshore location in greater than 1,000 feet of water
downstream refining and marketing operations
dry hole an unsuccessful exploration well that is plugged and abandoned, with associated costs written off to expense
exploratory wildcat and delineation, e.g., exploratory wells
feedstock crude oil, natural gas liquids and other materials used as raw materials for making gasoline and other refined products by the Company’s refineries | hydrocarbons organic chemical compounds of hydrogen and carbon atoms that form the basis of all petroleum products
on stream commencement of oil and gas production from a new field
3D seismic three-dimensional images created by bouncing sound waves off underground rock formations that are used to determine the best places to drill for hydrocarbons
throughput average amount of raw material processed in a given period by a facility
upstream oil and natural gas exploration and production operations, including synthetic oil operation
wildcat well drilled to target an untested or unproved geologic formation |
F-40