The Daily Magic Formula Stock for 12/02/2008 is Murphy Oil Corp. According to the Magic Formula Investing Web Site, the ebit yield is 36% and the EBIT ROIC is 25-50 %.
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Murphy Oil Corporation is a worldwide oil and gas exploration and production company with refining and marketing operations in the United States and the United Kingdom. As used in this report, the terms Murphy, Murphy Oil, we, our, its and Company may refer to Murphy Oil Corporation or any one or more of its consolidated subsidiaries.
The Company was originally incorporated in Louisiana in 1950 as Murphy Corporation. It was reincorporated in Delaware in 1964, at which time it adopted the name Murphy Oil Corporation, and was reorganized in 1983 to operate primarily as a holding company of its various businesses. Its operations are classified into two business activities: (1) â€śExploration and Productionâ€ť and (2) â€śRefining and Marketing.â€ť For reporting purposes, Murphyâ€™s exploration and production activities are subdivided into six geographic segments, including the United States, Canada, the United Kingdom, Malaysia, Ecuador and all other countries. Murphyâ€™s refining and marketing activities are subdivided into geographic segments for North America and United Kingdom. Murphy exited the gasoline retailing business in Canada during 2007, but the relatively insignificant historical results for the Canadian operations have been combined with U.S. refining and marketing operations in the North American segment. Additionally, â€śCorporateâ€ť activities include interest income, interest expense, foreign exchange effects and overhead not allocated to the segments.
The information appearing in the 2007 Annual Report to Security Holders (2007 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.
In addition to the following information about each business activity, data about Murphyâ€™s operations, properties and business segments, including revenues by class of products and financial information by geographic area, are provided on pages 14 through 25, F-12 and F-13, F-31 through F-39, and F-41 of this Form 10-K report and on pages 6 and 7 of the 2007 Annual Report.
At December 31, 2007, Murphy had 7,539 employees, including 2,890 full-time and 4,649 part-time.
Interested parties may access the Companyâ€™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 Corporationâ€™s website at www.murphyoilcorp.com.
Exploration and Production
The Companyâ€™s exploration and production business explores for and produces crude oil, natural gas and natural gas liquids worldwide. The Companyâ€™s exploration and production management team in Houston, Texas directs the Companyâ€™s worldwide exploration and production activities.
During 2007, Murphyâ€™s principal exploration and production activities were conducted in the United States by wholly owned Murphy Exploration & Production Company â€“ USA (Murphy Expro USA), in Ecuador, Malaysia and the Republic of Congo by wholly owned Murphy Exploration & Production Company â€“ 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. Murphyâ€™s crude oil and natural gas liquids production in 2007 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 worldâ€™s largest producer of synthetic crude oil.
Murphyâ€™s worldwide crude oil, condensate and natural gas liquids production in 2007 averaged 91,522 barrels per day, an increase of 4% compared to 2006. The increase was primarily due to start-up of production at the Kikeh field in Block K, offshore Sabah, Malaysia, in August 2007. Oil production was also higher in 2007 in Canada primarily due to a full year of production at Terra Nova and higher oil volumes at Syncrude. The Terra Nova field was shut down for major equipment maintenance for six months in 2006. Oil production in the U.S. Gulf of Mexico was lower in 2007 due to production declines at several fields. The Companyâ€™s worldwide sales volume of natural gas averaged 61 million cubic feet (MMCF) per day in 2007, down 19% from 2006 levels. The lower natural gas sales volumes were primarily attributable to production declines in 2007 for fields in South Louisiana and the Gulf of Mexico. Total worldwide 2007 production on a barrel of oil equivalent basis (six thousand cubic feet of natural gas equals one barrel of oil) was 101,702 barrels per day, up 1% compared to 2006.
Total production in 2008 is currently expected to average approximately 135,000 barrels of oil equivalent per day. The projected production increase in 2008 is related to a full year of oil production plus continued ramp up of volumes at the Kikeh field. In addition, initial natural gas production is expected during the year in Malaysia and from the Tupper area in western Canada. These improved volumes are expected to more than offset anticipated field declines in 2008 in the Gulf of Mexico, onshore South Louisiana and at Hibernia and Terra Nova.
In the United States, Murphy has production of oil and/or natural gas from four fields operated by the Company and four main fields operated by others. Of the total producing fields at December 31, 2007, six are in the deepwater Gulf of Mexico and two are onshore in Louisiana. The Companyâ€™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 produced approximately 13,000 barrels of oil per day and 45 million cubic feet of natural gas per day in the U.S. in 2007. These amounts represented 14% of total worldwide oil and 74% of worldwide natural gas production volumes. The Medusa field in Mississippi Canyon Blocks 538/582 is the only major field in the U.S. and represented 40% of total production on a barrel of oil equivalent basis during 2007. The Company operates and holds a 60% interest in Medusa, which produced total daily net oil and natural gas of about 7,000 barrels and 7 MMCF, respectively, in 2007. At December 31, 2007, the Medusa field has total net proved oil and natural gas reserves of approximately 9 million barrels and 11 billion cubic feet, respectively. Production from Medusa is expected to continue to decline in 2008 and should average 4,900 barrels of oil and 4 MMCF of natural gas on a daily basis. Total oil and natural gas reserves in the U.S. at December 31, 2007 were 31.2 million barrels and 113.3 billion cubic feet, respectively.
In Canada, the Company owns an interest in three nonoperated significant, long-lived assets, the Hibernia and Terra Nova fields offshore Newfoundland and Syncrude Canada Ltd. in northern Alberta. In addition, the Company owns interests in two heavy oil areas and one natural gas area in the Western Canadian Sedimentary Basin (WCSB). Murphy has a 6.5% interest in Hibernia and a 12% interest in Terra Nova in the Jeanne dâ€™Arc Basin, offshore Newfoundland. Total net production in 2007 was about 8,300 barrels of oil per day at Hibernia, while net production from Terra Nova was about 10,600 barrels of oil per day. Terra Nova was on production for all of 2007 following a six-month shut down for major equipment maintenance in 2006. Total 2008 net oil production at Hibernia and Terra Nova is anticipated to be approximately 7,100 and 8,700 barrels per day, respectively. Total net proved oil reserves at December 31, 2007 at Hibernia and Terra Nova were approximately 8.7 million barrels and 7.4 million barrels, respectively. 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 completed an expansion in 2006 by adding a third coker that allows for increased production. Total net production in 2007 was about 12,900 barrels of synthetic crude oil per day and is expected to average about 13,200 barrels per day in 2008. Although Syncrude produces a very high quality synthetic crude oil from bitumen, the U.S. Securities and Exchange Commission (SEC) considers Syncrude to be a mining operation, and not a conventional oil operation and therefore, does not allow the Company to include Syncrudeâ€™s reserves in its total proved oil reserves reported on page F-35. Total net reserves for Syncrude at year-end 2007 were approximately 128.4 million barrels. Daily net production in 2007 in the WCSB averaged about 12,100 barrels of mostly heavy oil and about 10 MMCF of natural gas. WCSB oil and natural gas production in 2008 is expected to decline to 8,000 barrels and nine MMCF per day, with the reduction mostly due to planned property sales. In January 2008, Murphy sold its 80% interest in Berkana Energy Corp. for net proceeds of approximately Cdn $103.8 million. Through early 2008, the Company has acquired approximately 80,000 acres of mineral rights in northeastern British Columbia in an area named Tupper. Although the Company has booked no proved reserves at Tupper at year-end 2007, a significant natural gas development has been sanctioned by the Companyâ€™s Board of Directors and development activities are underway. Initial natural gas production at Tupper is currently anticipated in the fourth quarter 2008.
Murphy produces oil and natural gas in the United Kingdom sector of the North Sea. Total 2007 net production in the U.K. amounted to about 5,300 barrels of oil per day and six MMCF of natural gas per day, which represented 6% of oil produced and 10% of natural gas produced by the Company during the year. Total 2008 net daily production levels in the U.K. are anticipated to average 4,600 barrels of oil and five MMCF of natural gas. Total proved reserves in the U.K. at December 31, 2007 were 18.8 million barrels of oil and 23.6 billion cubic feet of natural gas.
In Malaysia, the Company has majority interests in eight separate production sharing contracts (PSCs). The Company serves as the operator of all these areas, which cover approximately 9.6 million acres. Through 2006, Murphy had an 85% interest in two shallow water blocks, SK 309 and SK 311, offshore Sarawak. In February 2007, the Company renewed the contract on these two Sarawak blocks at a 60% interest for areas with no discoveries, while retaining its 85% interest in the portion of these blocks on which discoveries have been made. The West Patricia and Congkak fields in Block SK 309 produced about 8,700 net barrels of oil per day in 2007. Net production in 2008 is anticipated to decrease at these fields to about 4,900 barrels of oil per day due to field decline and a lower percentage of production allocable to the Company under the production sharing contract. The Company has also made multiple natural gas discoveries in these shallow-water Sarawak blocks. In February 2007, the Company finalized a gas sales contract for the Sarawak area with PETRONAS, the Malaysian state-owned oil company, with initial gas deliveries anticipated in the first quarter 2009. Total proved reserves of oil and natural gas at December 31, 2007 for Blocks SK 309/311 were 6.6 million barrels and 317 billion cubic feet of natural gas.
The Company made a major discovery at the Kikeh field in deepwater Block K, offshore Sabah, in 2002 and added another important discovery at Kakap in 2004. Further discoveries have been made in Block K at Senangin, Kerisi and Jangas. In 2006, the Company relinquished a portion of Block K and was granted a 60% interest in an extension of a portion of Block K covering 1.02 million acres. The Company retained its 80% interest at Kikeh, Kakap and other discoveries in Block K. First oil production from Kikeh began in August 2007, less than five years after the initial discovery. Production volumes at Kikeh averaged 11,600 net barrels of oil per day for the full year 2007 and the field produced about 40,000 net barrels per day in December 2007. Net oil production at Kikeh is anticipated to average 56,000 barrels per day for 2008 as additional wells are completed and brought online. In February 2007, the Company signed a Kikeh field natural gas sales contract with PETRONAS. The natural gas development at Kikeh will lead to initial production beginning at mid-year 2008, with an average net volume of 67 MMCF per day in the fourth quarter and 35 MMCF per day for the full year. Total proved reserves booked in Block K as of year-end 2007 were 76 million barrels of oil and 107 billion cubic feet of natural gas. These proved oil reserves do not include any volumes attributable to pressure maintenance programs that the Company utilizes at the Kikeh field.
In early 2006, the Company also added a 60% interest in a new PSC for Block P, which includes 1.05 million acres of the previously relinquished Block K area. Murphy drilled an unsuccessful wildcat well in Block P during 2006. The Company has an 80% interest in deepwater Block H offshore Sabah. In early 2007, the Company announced a significant natural gas discovery at the Rotan well in Block H, and in early 2008, the Company followed up with a discovery at Biris. The Company was awarded interests in two PSCs covering deepwater Blocks L (60%) and M (70%) in 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 remain capitalized pending the resolution of the ownership issue. The Company is unable to predict when or how ownership of Blocks L and M will be resolved. A total of 2.9 million gross acres associated with Blocks L and M have been included in the acreage table below.
Murphy relinquished 75% interests in most of Block PM 311 and all of Block PM 312, located offshore peninsular Malaysia, during 2007. However, Murphy retained its 75% interest in two discoveries at Kenarong and Pertang in Block PM 311. Murphy has requested gas holding agreements for Kenarong and Pertang pending a further study of available development options.
In Ecuador, Murphy owns a 20% working interest in Block 16, which is operated by Repsol-YPF under a participation contract that expires in January 2012. The Companyâ€™s net production was about 9,000 barrels of oil per day in 2007 and is expected to average about 7,200 barrels per day in 2008, with the decline expected due to reduced development drilling after a late 2007 government sharing adjustment. In October 2007, the government of Ecuador passed a law that increased its share of revenue for sales prices that exceed a base price (about $23.28 per barrel at December 31, 2007) from 50% to 99%. The government had previously enacted a 50% revenue sharing rate in April 2006. The working interest owners in Block 16 intend to initiate arbitration proceedings against the government claiming that they do not have a right under the contract to enforce a revenue sharing provision. The arbitration proceedings could take many months to reach conclusion. Meanwhile, the Company and its partners are actively negotiating a contract revision with the government.
The Company has interests in Production Sharing Agreements covering two offshore blocks in the Republic of Congo. These blocks are named Mer Profonde Sud (MPS) and Mer Profonde Nord (MPN), and together, 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 an oil discovery at Azurite Marine #1 in the southern block, MPS. In 2005, the Company successfully followed up the Azurite discovery with an appraisal well that tested at 8,000 barrels of oil per day from one zone. A third well in early 2006 further appraised the Azurite area. The Companyâ€™s Board of Directors approved the development of the Azurite field in late 2006. During 2007, the Company continued its development of the Azurite field, with first oil production currently anticipated in 2009. In late 2007, the Company sold down its interest in the MPS block, including the Azurite field, from 85% to 50%, subject to the approval of the government of the Republic of Congo, which is expected in early 2008. The initial sales price was $83.5 million with additional consideration of up to $26.5 million contingent upon achieving certain financial and operating goals for Azurite field development. In addition, the Company will receive a partial carry on costs for two upcoming exploration wells in MPS. Once the transfer is approved by the Congolese government, the Companyâ€™s net acreage will be reduced by approximately 495 thousand acres.
In June 2007, Murphy entered into a production sharing contact covering Block 37, offshore Suriname. Murphy operates this block and has an 80% interest. Block 37 covers approximately 2.1 million acres and has water depths ranging from 160 to 1,000 feet. The contract provides for an initial six-year exploration phase and requires the acquisition of 3D seismic and the drilling of two wells, the first of which is likely to be drilled in 2009.
The Company acquired a 40% interest and operatorship of an exploration permit covering approximately 1.0 million gross acres in Block AC/P36 in the Browse Basin offshore northwestern Australia in November 2007. The transfer of the interest to Murphy is pending government approval, which is expected in early 2008. Three-dimensional seismic was obtained in late 2007 and the first exploration well is anticipated to spud in late 2008.
Murphyâ€™s estimated net quantities of proved oil and gas reserves and proved developed oil and gas reserves at December 31, 2004, 2005, 2006 and 2007 by geographic area are reported on pages F-35 and F-36 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 seven years ended December 31, 2007 are shown on page 6 of the 2007 Annual Report. In 2007, the Companyâ€™s production of oil and natural gas represented approximately 0.1% of the respective worldwide totals.
Production expenses for the last three years in U.S. dollars per equivalent barrel are discussed on page 20 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-34 through F-41 of this Form 10-K report.
As used in the three tables that follow, â€śgrossâ€ť wells are the total wells in which all or part of the working interest is owned by Murphy, and â€śnetâ€ť wells are the total of the Companyâ€™s fractional working interests in gross wells expressed as the equivalent number of wholly owned wells.
Refining and Marketing
The Companyâ€™s refining and marketing businesses are located in the United States 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. During 2007, the Company closed eight gasoline stations in Canada and no longer has gasoline marketing operations in that country.
Murphy Oil USA, Inc. (MOUSA), a wholly owned subsidiary of Murphy Oil Corporation, owns and operates two refineries in the United States. The larger of its U.S. refineries is at Meraux, Louisiana, on the Mississippi River approximately 10 miles southeast of New Orleans. The refinery is located on fee land. The Companyâ€™s refinery at Superior, Wisconsin is also located on fee land. Murco Petroleum Limited (Murco), a wholly owned U.K. subsidiary, owns 100% interest in a refinery at Milford Haven, Wales. Murco acquired the remaining 70% of the Milford Haven refinery that it did not already own on December 1, 2007 and now fully operates the facility, which is primarily located on fee land.
In late August 2005, the Meraux, Louisiana refinery was severely damaged by flooding and high winds caused by Hurricane Katrina. The Meraux refinery was shut-down for repairs for about nine months following the hurricane and restarted in mid-2006. The majority of costs to repair the Meraux refinery are expected to be covered by insurance. Oil Insurance Limited (O.I.L.), the Companyâ€™s primary property insurance coverage, has informed insureds that it has currently estimated that recoveries for Hurricane Katrina damages will likely be no more than 46% of claimantsâ€™ eligible losses. Murphy has other commercial insurance coverage for repair costs not covered by O.I.L., but this coverage limits recoveries from flood damage to $50.0 million. Costs to repair the refinery were approximately $196.0 million. Based on the expected insurance recoveries and repair costs as described, the Company recorded expenses for repair costs not recoverable from insurance of $50.7 million in 2006 and a further $3.0 million in 2007. The final settlement and recovery of insurance could take several years to complete. At December 31, 2007, total receivables from insurance companies related to hurricane repairs at Meraux was $38.9 million.
In 2003, Murphy expanded the Meraux refinery allowing the refinery to meet low-sulfur gasoline specifications which became effective January 1, 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. During 2004 the Company also completed the addition of a fluid catalytic cracking gasoline hydrotreater unit at its Superior, Wisconsin refinery, that allows the refinery to meet low-sulfur gasoline specifications. In 2006, the isomerization unit at the Superior refinery was revamped to a hydrotreater and one of two existing naptha hydrotreaters was revamped to a kerosine hydrotreater.
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. Murphyâ€™s retail stations are primarily located in the parking lots of Wal-Mart Supercenters in 20 states and use the brand name Murphy USAÂ®. The Company also markets gasoline and other products at standalone stations under the Murphy ExpressÂ® brand. Branded wholesale customers use the brand name SPURÂ®. Refined products are supplied from 12 terminals that are wholly owned and operated by MOUSA and numerous terminals owned by others. Of the wholly owned terminals, three are supplied by marine transportation, three are supplied by truck, four are supplied by pipeline and two are adjacent to MOUSAâ€™s refineries. The Company opened a newly built finished products terminal near Jonesboro, Arkansas in 2007. MOUSA also receives products at terminals owned by others either in exchange for deliveries from the Companyâ€™s terminals or by outright purchase. At December 31, 2007, the Company marketed products through 973 Murphy stations and 153 branded wholesale SPUR stations. MOUSA plans to build additional retail gasoline stations at Wal-Mart Supercenters and other standalone locations in 2008.
As of December 31, 2007 all but two of the Companyâ€™s operated gasoline stations are located in the parking lots of Wal-Mart Supercenters. During 2007, the Company agreed to buy the land underlying most of these stations from Wal-Mart. Through February 2008, the Company had acquired 730 sites from Wal-Mart, and additional sites are expected to be purchased in the future. Ownership of the sites effectively terminates the master ground rent agreement as to these sites, and no further rent is payable to Wal-Mart for the purchased locations. For the remaining gasoline station sites not acquired from Wal-Mart, Murphy has master agreements that allow the Company to rent land from Wal-Mart. The master agreements contain general terms applicable to all rental sites in the United States. 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 represented 48.8% of consolidated Company revenues in 2007, 51.7% in 2006 and 44.6% in 2005. As the Company continues to expand the number of gasoline stations at Wal-Mart Supercenters and other locations, total revenue generated by this business is expected to grow.
Murphy owns a 20% interest in a 120-mile refined products pipeline, with a capacity of 165,000 barrels per 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 the Louisiana Offshore Oil Port LLC (LOOP), 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. In December 2006, Murphy acquired an additional 10.7% interest in the first 22 miles of this pipeline from Clovelly to Alliance, Louisiana, thereby raising its ownership interest to 40.1%; the Company owns 100% of the remaining 24 miles from Alliance to Meraux. This crude oil pipeline is connected to another companyâ€™s pipeline system, allowing crude oil transported by that system to also be shipped to the Meraux refinery.
In 2007, Murphy owned approximately 1.0% of the crude oil refining capacity in the United States and its market share of U.S. retail gasoline sales was approximately 2.2%.
At the end of 2007, Murco distributed refined products in the United Kingdom from the wholly-owned 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 Companyâ€™s terminals, and 389 branded stations primarily under the brand name MURCO. The Company owns 162 of these branded stations and the remainder are branded dealers.
A statistical summary of key operating and financial indicators for each of the seven years ended December 31, 2007 are reported on page 7 of the 2007 Annual Report.
MANAGEMENT DISCUSSION FROM LATEST 10K
Murphy Oil Corporation is a worldwide oil and gas exploration and production company with refining and marketing operations in the United States and United Kingdom. A more detailed description of the Companyâ€™s significant assets can be found in Item 1 of this Form 10-K report.
Murphy generates revenue primarily by selling oil and natural gas production and refined petroleum products to customers at hundreds of locations in the United States, Canada, the United Kingdom, Malaysia and other countries. The Companyâ€™s revenue is highly affected by the prices of oil, natural gas and refined petroleum products that 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 the U.S. that are primarily located at Wal-Mart Supercenters, the purchase prices for these commodities also have a significant effect on the Companyâ€™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 and administration. Profits and generation of cash in the Companyâ€™s refining and marketing operations are dependent upon achieving adequate margins, which are determined by the sales prices for refined petroleum products less the costs of purchased refinery feedstocks and gasoline 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.
Worldwide oil prices were higher in 2007 than in 2006, while the average price for North American natural gas was up only slightly in 2007 compared to 2006. The average price for a barrel of West Texas Intermediate crude oil in 2007 was $72.25, an increase of 9% compared to 2006. The NYMEX natural gas price in 2007 averaged $7.11 per million British Thermal Units (MMBTU), up 1% from 2006. Changes in the price of crude oil and natural gas have a significant impact on the profitability of the Company, especially the price of crude oil as oil represented approximately 90% of the total hydrocarbons produced on an energy equivalent basis by the Company in 2007. If the prices for crude oil and natural gas decline significantly in 2008 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 Companyâ€™s refining and marketing operating profits.
Results of Operations
The Company had net income in 2007 of $766.5 million, $4.01 per diluted share, compared to net income in 2006 of $644.7 million, $3.41 per diluted share. In 2005 the Companyâ€™s net income was $854.7 million, $4.55 per diluted share. The net income improvement in 2007 compared to 2006 primarily related to higher earnings generated by both the exploration and production and refining and marketing businesses. The net cost of corporate activities was higher, however, in 2007 than in 2006. The lower net income in 2006 compared to 2005 was caused by a combination of lower earnings in the Companyâ€™s exploration and production and refining and marketing operations and higher net costs for corporate activities. Further explanations of each of these variances are found in the following sections.
Income from continuing operations was $766.5 million, $4.01 per diluted share, in 2007, $644.7 million, $3.41 per diluted share, in 2006, and $846.1 million, $4.50 per diluted share, in 2005.
Income from discontinued operations was $8.6 million, $0.05 per diluted share, in 2005. There were no results from discontinued operations in 2007 and 2006. 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, which generated an after-tax gain on the sale of $171.1 million in 2004. Income from discontinued operations in 2005 related to a favorable adjustment of income taxes associated with the gain on sale of the western Canada properties in 2004. In accordance with Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the favorable tax adjustment associated with the sale in 2005 has been presented as Discontinued Operations in the consolidated statement of income for the year ended December 31, 2005.
As explained in Note P to the consolidated financial statements, net income in 2006 and all prior years have been adjusted to reflect the adoption of FSP AUG AIR-1, Accounting for Planned Major Maintenance Activities, in 2007. Consequently, net income in 2006 and 2005 as presented above increased by $6.4 million ($.04 per diluted share) and $8.2 million ($.04 per diluted share), respectively, from the amounts previously reported.
2007 vs. 2006 â€“ Net income in 2007 was $766.5 million, $4.01 per diluted share, compared to $644.7 million, $3.41 per diluted share, in 2006. The improvement in consolidated net income in 2007 of $121.8 million compared to 2006 was primarily related to higher earnings in both major businesses â€“ exploration and production (â€ś E&Pâ€ť) and refining and marketing (â€śR&Mâ€ť or â€śdownstreamâ€ť). The net costs of corporate activities were higher in 2007 and partially offset the improved results in E&P and R&M. Earnings in the E&P business improved by $40.3 million in 2007 as this business benefited from higher oil sales prices, lower exploration expenses and lower income taxes in 2007 compared to 2006. E&P earnings were adversely affected in 2007 by lower sales volumes for oil and natural gas and slightly lower realized natural gas sales prices as well as higher expenses for production, depreciation, depletion and administration. The R&M business generated record company profits in 2007, increasing $95.1 million compared to 2006. The improvement was primarily due to stronger U.S. refining margins in 2007 compared to 2006, a fully operational refinery at Meraux, Louisiana, during 2007, and lower hurricane repair expenses in 2007, but R&M earnings in 2007 included an unfavorable impact from noncash inventory revaluations. The Meraux refinery was shut-down for repairs for the first five months of 2006 following significant damage caused by Hurricane Katrina in late August 2005. The Company incurred significant repair costs in 2006 at Meraux following Hurricane Katrina, certain of which were not recoverable through insurance policies. In the U.K., the Company acquired the remaining 70% interest in the Milford Haven, Wales, refinery in late 2007. Under the Companyâ€™s last-in first-out accounting policy for inventory, an after-tax noncash charge of $59.5 million was recorded in 2007 to reduce the carrying value of crude oil and refined products inventory to beginning of year prices, which were significantly lower than at the end of the year. The net costs of corporate activities increased by $13.6 million in 2007 compared to 2006, with the cost increase mostly attributable to higher net interest expense and higher losses on transactions denominated in foreign currencies. The higher net interest expense was caused by higher average borrowing levels, partially offset by a higher level of interest costs capitalized to E&P development projects. The U.S. dollar generally weakened against other significant foreign currencies used in the Companyâ€™s business in 2007, especially compared to the Canadian dollar. The 2007 period included lower corporate administrative costs mostly due to higher expense in 2006 for an educational assistance contribution commitment.
Sales and other operating revenues were $4.1 billion higher in 2007 than in 2006 mostly due to higher sales volumes and sales prices for gasoline and other refined products, higher sales prices for crude oil produced by the Company, and higher sales volumes for merchandise at retail gasoline stations. Sales volumes for oil and natural gas were lower in 2007 than in 2006. Gain/loss on sales of assets in 2007 was $9.8 million unfavorable to 2006 as the Company had no major asset sales in 2007. Interest and other income was lower by $3.0 million in 2007 due mostly to higher losses on foreign currency exchange attributable to a continued weakening of the U.S. dollar against the primary foreign currencies affecting the Companyâ€™s operations, which include the Canadian dollar, the British pound sterling, the Euro and the Malaysian ringgit. Crude oil and product purchases expense increased by $3.7 billion in 2007 compared to 2006 due to a combination of higher purchase prices and throughput volumes of crude oil and other feedstocks at the Companyâ€™s refineries, higher prices and volumes of refined petroleum products purchased for sale at retail gasoline stations, and higher levels of merchandise purchased for sale at the gasoline stations. The higher crude oil purchase volumes in 2007 were caused by the Meraux refinery being operational throughout 2007 following about five months of downtime in 2006 for hurricane-related repairs. Operating expenses increased by $218.8 million in 2007 compared to 2006 and included higher refinery and retail station costs, higher workover and repair costs for Gulf of Mexico oil and gas fields, and higher costs for oil and gas field operations in Malaysia, the U.K. and Ecuador and for synthetic oil operations at Syncrude. Exploration expenses were $16.2 million lower in 2007 than in 2006 primarily associated with less dry hole and geophysical expenses in Malaysia, but partially offset by higher costs in Canada for dry holes, geophysical, lease amortization and settlement of two work commitments on the Scotian Shelf. Selling and general expenses were $0.8 million higher in 2007 than in 2006 as higher compensation, insurance and Berkana Energy administrative costs in the just completed year were almost offset by lower costs associated with an educational assistance program called the El Dorado Promise. The Company acquired 80% of Berkana Energy in December 2006, and subsequently sold this investment in January 2008. Depreciation, depletion and amortization expense was $105.8 million higher in 2007 compared to 2006 due mostly to higher barrel-equivalent unit rates for depreciation for virtually all E&P segments and higher depreciation for the Meraux refinery and retail gasoline stations. Impairment of long-lived assets of $40.7 million in 2007 primarily related to closing 55 underperforming gasoline stations in the U.S. and Canada. Accretion of asset retirement obligations increased by $5.3 million in 2007 mostly due to additional abandonment obligations incurred as additional Kikeh development wells were drilled during the year, and higher anticipated future abandonment costs on existing wells in the U.S. Net costs associated with hurricanes was lower in 2007 by $106.2 million mostly due to uninsured repair costs incurred in 2006 at the Meraux refinery following Hurricane Katrina in 2005. The costs recorded in 2007 related to a downward adjustment for anticipated insurance recoveries at the Meraux refinery based on recently updated loss limits published by the Companyâ€™s primary property insurer. Interest expense increased by $22.9 million in 2007 mostly associated with a higher average level of outstanding borrowings during the year compared to 2006. The amount of interest costs capitalized to property, plant and equipment increased by $6.8 million in 2007 due to higher levels of spending on E&P development projects in Malaysia, the U.S. and the Republic of Congo. Minority interest in operations of Berkana Energy in Canada was favorable $0.6 million in 2007 compared to 2006. Income tax expense was $77.0 million higher in 2007 than in 2006 and was mainly attributable to higher pretax income levels. The effective income tax rate for consolidated earnings rose from 37.9% in 2006 to 38.0% in 2007. The tax rate in both years was higher than the U.S. federal statutory tax rate of 35.0% due to a combination of U.S. state income taxes, certain foreign tax rates that exceed the U.S. federal tax rate, and certain exploration and other expenses in foreign taxing jurisdictions for which no income tax benefit is currently being recognized because the ability to obtain tax benefits for these costs in future years is uncertain. The tax rates in both years benefitted, however, from overall favorable effects of tax rate changes in foreign countries.
2006 vs. 2005 â€“ Net income in 2006 was $644.7 million, $3.41 per diluted share, compared to $854.7 million, $4.55 per diluted share, in 2005. Net income in 2005 included income from discontinued operations of $8.6 million, which was $0.05 per share. The $210.1 million decline in net income in 2006 was primarily due to lower earnings in both the Companyâ€™s E&P and downstream businesses, plus higher net costs for corporate activities. The Companyâ€™s E&P earnings declined by $133.2 million in 2006 due to several factors, including an after-tax gain of $104.5 million in 2005 related to a sale of most mature oil and natural gas properties on the continental shelf of the Gulf of Mexico, plus in 2006, lower sales volumes for crude oil and natural gas caused by lower production levels for these products, lower natural gas sales prices in North America and higher production and administrative expenses. The 2006 E&P results were favorably impacted by higher crude oil sales prices, lower exploration expenses, lower hurricane-related costs and higher income tax benefits due to various tax rate changes. Company-wide, the net costs associated with hurricanes were $42.5 million higher in 2006 compared to 2005. Hurricane costs in the Companyâ€™s R&M business were $59.8 million higher in 2006 due to more uninsured costs associated with repairs at the Meraux, Louisiana refinery, clean-up of a crude oil spill that occurred at the refinery as a result of damages from Hurricane Katrina, and settlement of litigation associated with the oil spill. Hurricane costs in the Companyâ€™s E&P business were lower in 2006 by $16.9 million due to lower costs for equipment and facilities repair, discretionary employee assistance and hurricane-related insurance. Earnings in the R&M business were $21.0 million lower in 2006 compared to 2005, with the earnings reduction primarily caused by the aforementioned higher hurricane-related costs. Excluding the higher hurricane costs, U.S. downstream earnings improved in 2006 compared to 2005, while 2006 earnings for downstream operations in the U.K. were down $7.4 million from record levels in 2005. The Company continued to expand its retail gasoline station business by adding 123 sites in 2006, with virtually all such additions located at Wal-Mart Supercenters. The net costs of corporate activities were $47.2 million higher in 2006 than 2005. These costs increased mostly due to an educational assistance contribution commitment amounting to $25.1 million after-tax, plus the unfavorable effects of foreign currency exchange movements as the U.S. dollar weakened against most other major currencies used by the Companyâ€™s operations, including the British pound sterling and Euro. In addition, corporate activity costs in 2006 were unfavorable because 2005 included income tax benefits of $9.7 million from settlement of U.S. income tax audits.
Sales and other operating revenues in 2006 were $2.6 billion higher than in 2005 mostly due to higher sales volumes and sales prices in the latter year for refined petroleum products. In addition, merchandise sales at retail gasoline stations increased in 2006 and the sales price of crude oil was higher in 2006. Revenue was unfavorably affected in 2006 by lower sales volumes of crude oil and lower sales volumes and prices for natural gas. Gain on sale of assets before income taxes amounted to $9.4 million in 2006 compared to $175.1 million in 2005. The prior year included a pretax gain of $165.0 million related to the sale of oil and natural gas properties on the Gulf of Mexico continental shelf. Interest and other income in 2006 was unfavorable to the prior year by $3.3 million due mostly to higher foreign exchange charges associated with the unfavorable effects of the U.S. dollar weakening against the British pound sterling and Euro. Crude oil and product purchases expense increased by $2.4 billion in 2006 compared to 2005 due to higher prices for crude oil and other purchased refinery feedstocks, higher prices and volumes of refined petroleum products purchased for sale at retail gasoline stations, and higher levels of merchandise purchased for sale at these gasoline stations. These higher costs were partially offset by lower volumes of crude oil purchased for feedstock in 2006 because the Meraux refinery was off-line for repairs for the first five months of the year. Operating expenses increased by $257.5 million in 2006 compared to 2005 due to higher repairs and other production expenses in the Companyâ€™s E&P operations, higher costs to operate retail gasoline stations primarily due to more stations in operation, and higher refinery operating costs mostly associated with increased labor costs at the Companyâ€™s Meraux refinery. Exploration expenses were lower in 2006 compared to 2005 by $13.2 million primarily due to lower dry hole charges in the current year in the Republic of Congo, but partially offset by higher dry hole and seismic and geophysical costs in the U.S. Selling and general expenses increased $69.7 million in 2006 due to various factors during the year, including costs for an educational assistance contribution commitment, the costs of reorganizing the Companyâ€™s U.S. E&P operations, higher costs for professional consultants, and the initial costs to expense the grant-date fair value of stock options which began in 2006. Depreciation, depletion and amortization expense was $12.8 million lower in 2006 than 2005 generally due to lower volumes of crude oil and natural gas sold by the Companyâ€™s E&P business. Depreciation expense in the downstream business was higher in 2006 mostly due to the continued addition of retail gasoline stations in the U.S. Accretion of asset retirement obligations increased by $1.2 million in 2006 mostly due to higher asset retirement obligations for Malaysian operations associated with drilling development wells at the Kikeh field during the year. The reasons for higher costs associated with hurricanes in 2006 were included in the previous paragraph. Interest expense increased in 2006 by $5.2 million due to higher average borrowings under the Companyâ€™s credit facilities. The amount of interest costs capitalized to development projects increased by $4.5 million in 2006 compared to 2005 due to higher capitalized costs associated with the Kikeh field, offshore Sabah Malaysia, and a field in the deepwater Gulf of Mexico. Income tax expense in 2006 was lower than in 2005 by $145.2 million due to lower pretax earnings in 2006 and net tax benefits in the year from changes in tax rates in various taxing jurisdictions. The effective income tax rate for consolidated earnings in 2006 was 37.9% and included a net benefit of $19.7 million from the reduction of Federal and provincial tax rates in Canada offset in part by an increase in the tax rate on oil operations in the U.K. The effective tax rate in 2005 was 38.9% of consolidated pretax earnings. The tax rate in both years was higher than the U.S. federal statutory tax rate of 35.0% due to a combination of U.S. state taxes, certain foreign tax rates that exceed the U.S. federal tax rate, and certain exploration and other expenses in foreign taxing jurisdictions for which no income tax benefit is currently being recognized because the ability to obtain tax benefits for these costs in future years is uncertain.
Segment Results â€“ In the following table, the Companyâ€™s results of operations for the three years ended December 31, 2007 are presented by segment.
Exploration and Production â€“ Earnings from exploration and production operations were $657.1 million in 2007, $616.8 million in 2006 and $750.0 million in 2005. E&P earnings improved in 2007 compared to 2006 primarily due to higher average realized oil sales prices for the Companyâ€™s production. In addition, exploration expenses were lower by $16.1 million in 2007. Both years were favorably affected by income tax benefits associated with tax rate reductions in foreign countries. The 2007 results were unfavorably impacted compared to 2006 by lower oil and natural gas sales volumes, lower realized natural gas sales prices in North America and higher expenses for production, depreciation, depletion, administration and accretion of discounted abandonment liabilities. Crude oil sales volumes in 2007 were 3% lower than in 2006, despite a 4% increase in crude oil production in 2007 compared to 2006. The lower sales volumes were caused by the timing of sale transactions as the Company had a larger inventory of unsold crude oil at year-end 2007 compared to a year earlier. The 2007 increase in crude oil inventory, which is primarily at the Kikeh field in Malaysia, is expected to return to normal levels during 2008. During 2007, lower oil sales volumes in the U.S. and Ecuador were only partially offset by higher oil sales volumes in Malaysia and Canada. The lower sales volumes in the U.S. were due to field declines in the Gulf of Mexico, while lower sales volumes in Ecuador were caused by make-up sales volumes in 2006 that related to a prior year. Higher oil sales volumes in Malaysia were mostly caused by start-up of the significant Kikeh field, offshore Sabah, in August, partially offset by lower production at the West Patricia field, offshore Sarawak. Higher volumes in Canada were attributable to better production volumes at the Terra Nova field in the Jeanne dâ€™Arc basin, offshore Newfoundland, which was shut-in for repairs for about six months in 2006. Natural gas sales volumes were 19% lower in 2007 than 2006 and the reduction was mostly due to field declines for maturing fields in the Gulf of Mexico and onshore south Louisiana as well as lower natural gas production at U.K. North Sea fields. The Companyâ€™s average realized oil sales price was 20% higher in 2007 than 2006, while the average North American natural gas sales price was 5% lower in 2007.
The $133.2 million reduction in 2006 earnings compared to 2005 was mostly attributable to lower production of crude oil and natural gas, which led to lower sales volumes for these products. Lower natural gas sales prices and higher production and administrative expenses in 2006 and a $104.5 million after-tax gain on sale of oil and natural gas properties on the continental shelf of the Gulf of Mexico in 2005 also were factors that led to lower E&P earnings in 2006. E&P earnings in 2006 were favorably impacted by higher realized oil sales prices, lower exploration expenses, lower hurricane-related expenses and income tax benefits associated with tax rate changes enacted during the year. Crude oil sales volumes were down in 2006 by 13% compared to 2005, while natural gas sales volumes were down by 17%. Oil sales volumes were lower in 2006 primarily due to lower production at maturing fields in the Gulf of Mexico, lower production at the Terra Nova field, offshore Newfoundland, due to the field being shut-in for six months for major equipment repairs, and lower production at West Patricia, offshore Sarawak Malaysia, due to a lower volumetric sharing percentage allocable to the Company under the production sharing contract as the field matures. The decline in natural gas sales volumes in 2006 was attributable to both the mid-2005 sale of mature gas properties on the Gulf of Mexico continental shelf and lower production from gas fields onshore south Louisiana. The Companyâ€™s average worldwide realized crude oil sales price increased 14% in 2006, while the average realized sales price for North American natural gas decreased 10%.
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-38 and F-39 of this Form 10-K report. Average daily production and sales rates and weighted average sales prices are shown on page 6 of the 2007 Annual Report.
The Companyâ€™s crude oil, condensate and natural gas liquids production averaged 91,522 barrels per day in 2007, 87,817 barrels per day in 2006 and 101,349 barrels per day in 2005. In 2007, crude oil, condensate and natural gas liquid production increased by 3,705 barrels per day, or 4%, primarily due to start-up in August of the Kikeh field in Block K, offshore Sabah, Malaysia. This prolific field came on only five years after discovery. Kikeh produced 11,658 barrels of oil per day for the full-year 2007 and almost 40,000 barrels per day in December 2007. This field will continue to ramp-up production during 2008 as more wells are brought on production. Oil production also increased in 2007 at Terra Nova, offshore eastern Canada, at Syncrude in Alberta, and in Ecuador. Oil volumes declined in 2007 at most other areas, including the U.S. and at Hibernia, West Patricia, the U.K. North Sea and the Western Canadian Sedimentary Basin (WCSB). Terra Nova produced throughout 2007 after being off-line for major equipment repairs for six months in 2006. Total production at Terra Nova was 10,557 barrels per day in 2007 and 3,900 barrels per day in 2006. Syncrude production totaled 12,948 barrels per day in 2007 compared to 11,701 barrels per day in 2006. The 2007 production increase at Syncrude was mostly attributable to a third coker unit that started up during 2006. Oil production totaled 8,946 barrels per day at Block 16 in Ecuador, up 338 barrels per day due to a more significant development drilling campaign in 2007. Oil production declined in the U.S. from 21,112 barrels per day in 2006 to 12,989 barrels per day in 2007. The reduction was due to declines at various maturing fields in the Gulf of Mexico. Heavy oil production in the WCSB fell from 12,613 barrels per day in 2006 to 11,524 barrels per day in 2007, primarily due to a slower development drilling program for non-operated fields in Alberta. Oil production at Hibernia, offshore Newfoundland, was 8,314 barrels per day in 2007 compared to 10,996 barrels per day in 2006. The Hibernia field is experiencing production decline. Oil production in the U.K. was down from 7,146 barrels per day in 2006 to 5,281 barrels per day in 2007, with the reduction caused by declining production at the Companyâ€™s primary fields in the North Sea. The West Patricia field, offshore Sarawak Malaysia, had net production of 8,709 barrels per day in 2007 after production levels of 11,298 barrels per day in 2006. West Patricia is also experiencing declining production along with an increased government take under the production sharing contract.
Production of crude oil, condensate and natural gas liquids was 13% lower in 2006 compared to 2005 primarily due to lower volumes produced in the U.S. Gulf of Mexico and offshore eastern Canada. U.S. oil production of 21,112 barrels per day in 2006 was down by 18% from 2005 levels. The reduction in the U.S. related to lower volumes at deepwater fields in the Gulf of Mexico and oil volumes produced in 2005 from fields on the continental shelf that were sold in the middle of that year. U.S. oil production in 2006 was virtually unaffected by downtime for tropical storms and hurricanes, while 2005 volumes were adversely affected by downtime associated with Hurricanes Katrina and Rita. Terra Nova, offshore eastern Canada, was off production for about one-half of 2006 for major equipment repairs. The floating production, storage and offloading vessel was taken to Europe for turnaround and production restarted in mid-November 2006. Production at Terra Nova was 3,900 barrels per day in 2006, down 64% from 2005 levels. Production at Hibernia totaled 10,996 barrels per day, which was 10% below 2005, with the decline due primarily to more downtime for equipment reliability issues in 2006. Total heavy oil production in WCSB increased 7% in 2006 and totaled 12,613 barrels per day. This increase was attributable to an ongoing development drilling program during 2006 at the Seal field in Alberta. Light oil production in the WCSB fell 21% to 443 barrels per day in 2006 mostly due to less condensate produced at the Rimbey gas field in Alberta. Synthetic oil production at Syncrude increased 10% in 2006 and was 11,701 barrels per day. A third coker unit was started up during 2006, and the new unit permits a larger volume of bitumen to be processed at the plant. The new coker experienced various start up issues, but was operating near capacity at year-end 2006. All oil production in Malaysia during 2006 came from the West Patricia and adjoining Congkak fields in Block SK 309 offshore Sarawak. Net oil production from Malaysia was 11,298 barrels per day in 2006, 16% lower than in 2005 as the production sharing contract allocates a smaller portion of gross production to the Companyâ€™s account in both a higher price environment and as prior costs are recovered. Gross production volumes at the Malaysian fields fell only 5% in 2006. Oil production offshore the United Kingdom fell 11% to 7,146 barrels per day. The most significant U.K. decline in 2006 occurred at the Schiehallion field and was primarily caused by a fire at the facilities used by this field. Total net oil produced at Block 16 in Ecuador was 8,608 barrels per day in 2006, a 9% increase from 2005 as a development drilling campaign continued in 2006. Oil sales volumes in Ecuador significantly exceeded production in 2006 due to selling 853,000 barrels of oil in settlement of a dispute with partners over 2004 oil production that was originally withheld from the Company.
Worldwide sales of natural gas were 61.1 million cubic feet (MMCF) per day in 2007, 75.3 million in 2006 and 90.2 million in 2005. Natural gas sales in the United States fell 21% in 2007 and averaged 45.1 MMCF per day. The decline of 11.7 MMCF per day in 2007 was due to declines at various fields in the deepwater Gulf of Mexico and onshore South Louisiana. Natural gas sales volumes in 2007 increased 2% in Canada and averaged 9.9 MMCF per day. Natural gas sales volumes in the U.K. fell 31% in 2007 and averaged 6.0 MMCF per day. The lower U.K. gas sales volumes were attributable to lower gas volumes sold from two oil fields in the North Sea.
Sales of natural gas in the United States were 56.8 MMCF per day in 2006, down 19% from 2005. The reduced U.S. natural gas sales volume in 2006 was attributable to a combination of lower volumes produced onshore south Louisiana due to field decline and no volumes produced in 2006 at Gulf of Mexico continental shelf fields that were sold in mid-2005. In the Gulf of Mexico, production at a new field that came onstream in 2006 served to essentially offset lower volumes at other deepwater Gulf of Mexico fields. U.S. natural gas sales volumes in 2006 were virtually unaffected by downtime for tropical storms and hurricanes, while volumes in 2005 were adversely affected by downtime associated with Hurricanes Katrina and Rita. Natural gas sales volumes in Canada of 9.8 MMCF per day in 2006 were 6% lower than 2005, mostly caused by normal field decline in the Rimbey area. Natural gas sales volumes in the U.K. in 2006 were 8.7 MMCF per day, 8% lower than in 2005. The 2006 decline for natural gas sales volumes in the U.K. was wholly attributable to make-up gas volumes sold in 2005 at an offshore field in order to balance under-sold production in earlier years. Excluding the make-up volumes in 2005, U.K. natural gas sales volumes in 2006 would have exceeded 2005 amounts.
Worldwide crude oil sales prices have risen in each of the last two years due to the combination of a strong world economy, real and perceived instability in worldwide crude oil production levels, and effective production output controls by OPEC producers. The Companyâ€™s average realized sales price across all of its oil production was $62.05 per barrel in 2007, up 20% from the 2006 average of $51.62 per barrel. In the U.S., the Company realized an average price of $65.57 per barrel, up 14% from 2006. The average sales price for heavy oil produced in Canada was $32.84 per barrel, 27% higher than in 2006. Hibernia and Terra Nova sales prices averaged $71.43 and $68.54 per barrel, respectively, during 2007, which were increases of 13% and 15%. Synthetic oil production sold for $74.35 per barrel, up 18% from a year earlier. U.K. oil prices increased 6% to $68.38 per barrel in 2007. In Malaysia, oil produced at the West Patricia field sold for 14% more in 2007 than in 2006, with an average of $59.05 for the just completed year. The Kikeh field came on stream in August 2007 and all sales from this field occurred in the stronger price environment during the fourth quarter 2007 at an average of $90.84 per barrel. The average realized sales price after revenue sharing with the Ecuadorian government for Block 16 oil was $36.47 per barrel, an increase of 8% from 2006. For most of the year, the government received a 50% share of realized sales prices that exceeded a benchmark price that escalates with the monthly U.S. Consumer Price Index. However, in mid-October the government changed its share of such revenue from 50% to 99%. At year-end 2007, the benchmark oil price for Block 16 was approximately $23.28 per barrel. The Company and its partners in Block 16 intend to initiate arbitration proceedings claiming that the government does not have the right under the contract to change this sharing arrangement.
The Company realized an average per barrel sales price of $51.62 for crude oil and condensate in 2006, up 14% from the 2005 average of $45.25 per barrel. The average realized oil sales price in 2006 in the U.S. was up 21% at $57.30 per barrel. The average sales price of Canadian heavy oil was $25.87 per barrel, also a 21% increase compared to 2005. Realized average prices per barrel for Hibernia and Terra Nova oil sales in 2006 were $63.48 and $59.79, respectively, with each up about 20% from 2005 averages. Synthetic oil production was sold at $63.23 per barrel in 2006, up 9% from 2005 prices. The realized sales price for synthetic oil did not rise as much as other oil because of higher volumes of similar crudes available in the market for which demand did not keep pace with the growth. Average crude oil prices in Malaysia of $51.78 per barrel in 2006 were 12% higher than 2005, while U.K. prices in 2006 rose 22% to $64.30 per barrel. The average oil price realized in Ecuador of $33.79 per barrel rose only 4% from 2005 as the Ecuadorian government passed a revenue sharing law that became effective in April 2006, whereby the government received a revenue-share of 50% for realized prices exceeding a benchmark price that escalates with the inflation rate.
The Companyâ€™s North American natural gas sale prices in 2007 and 2006 did not rise in tandem with higher crude oil prices. The Companyâ€™s average realized North American natural gas sales prices fell 5% in 2007 to $7.19 per thousand cubic feet (MCF). In the U.K., the average 2007 natural gas price rose 3% to $7.54 per MCF.
North American gas sales prices averaged $7.57 per MCF in 2006, down 10% from the 2005 average. The sales price for natural gas in the U.K. was up 27% and averaged $7.34 per MCF.
Based on 2007 sales volumes and deducting taxes at marginal rates, each $1.00 per barrel and $0.10 per MCF fluctuation in prices would have affected earnings from exploration and production operations by $19.8 million and $1.4 million, respectively. The effect of these price fluctuations on consolidated net income cannot be measured precisely because operating results of the Companyâ€™s refining and marketing segments could be affected differently.
Production cost per equivalent barrel increased in the U.S. in 2007 mostly due to higher workover and field repairs and lower production volumes. The rate per equivalent barrel in 2006 was up from 2005 mostly due to higher insurance costs coupled with lower overall production. The per-unit costs for Canadian conventional oil and gas operations, excluding Syncrude was lower in 2007 than 2006 primarily due to higher production levels and lower repair costs at Terra Nova in 2007. The field was shut-in for major repairs for six months in 2006. Canadian costs excluding Syncrude rose significantly in 2006 due to lower production volumes and higher repair costs at Terra Nova while off-line for major repairs, plus a higher mix of more costly heavy oil production versus lighter oils. Higher production costs per barrel for Canadian synthetic oil operations in 2007 were primarily due to a higher net profit royalty rate and a higher foreign exchange rate. In 2006 higher costs for synthetic operations were mostly attributable to higher coker repair costs and higher compensation costs. The higher average U.K. cost per barrel in 2007 was mostly due to higher maintenance costs, lower oil production at the North Sea fields and a higher foreign exchange rate. The higher per-unit cost in Malaysia in 2007 was due to the start-up phase for Kikeh oil and a lower production level for West Patricia. Higher 2006 costs per barrel produced in the U.K. and Malaysia were mostly attributable to higher facility maintenance costs. Higher per-unit operating costs in Ecuador in 2007 were primarily caused by increasing water handling costs as Block 16 wells mature. Higher per-unit operating costs in Ecuador in 2006 compared to 2005 were mostly attributable to higher field operating costs in the Amazon region where Block 16 is located.
Dry holes expense was $43.9 million less in 2007 than 2006 primarily due to a lower level of exploration drilling activity in 2007. With mostly new E&P management in 2007, much of the year was spent reevaluating exploration drilling prospects on a worldwide basis. Dry holes expense was $15.0 million lower in 2006 than 2005 mostly due to less unsuccessful wildcat drilling in the Republic of Congo, but partially offset by higher unsuccessful drilling costs in the Gulf of Mexico. Geological and geophysical (G&G) expenses were $5.4 million less in 2007 than 2006 primarily due to lower spending on 3-D seismic in Blocks SK 311 and H, and lower geophysical analyses on PM Blocks 311/312, all in Malaysia. The lower Malaysian costs were partially offset by higher seismic costs in 2007 in the Gulf of Mexico and offshore Australia, and higher geophysical studies offshore the Republic of Congo. G&G expenses in 2006 were about level with 2005 as higher costs in the Gulf of Mexico were essentially offset by lower spending offshore eastern Canada. Other exploration expenses in 2007 were $22.5 million higher than 2006 mostly due to a $21.9 million settlement of unfulfilled work commitments on two expiring Scotian Shelf leases. Other exploration expenses in 2006 were $2.4 million higher than in 2005 mostly due to higher administrative costs for international exploration activities. Undeveloped leasehold amortization expense rose $10.7 million in 2007 compared to 2006 primarily due to amortization of land acquisitions at the Tupper property in northeast British Columbia. Undeveloped leasehold amortization expense in 2006 was virtually flat with 2005.
A $2.6 million charge for asset impairment in 2007 was taken to write-down an unused E&P administrative office to its estimated fair value.
Costs of $1.9 million and $18.8 million were incurred in 2006 and 2005, respectively, in the Companyâ€™s exploration and production operations for uninsured costs to repair damages and to recognize associated higher insurance costs caused by hurricanes in the Gulf of Mexico. These costs were related to the effects of Hurricanes Katrina and Rita, and also included in 2005 discretionary assistance to employees in the New Orleans area after Hurricane Katrina.
Depreciation, depletion and amortization expense related to exploration and production operations totaled $376.8 million in 2007, $297.0 million in 2006 and $319.1 million in 2005. The $79.8 million increase in 2007 compared to 2006 was caused by generally higher per-unit rates for development capital, the start-up of the Kikeh field, and an increase in foreign exchange rates in Canada and the U.K. The $22.1 million reduction in 2006 compared to 2005 was attributable to lower oil and natural gas sales volumes, partially offset by generally higher per-barrel capital amortization caused by higher costs for development operations and negative U.S. reserve revisions. The Company continues to experience high drilling and related costs caused by a strong demand for such services.
The exploration and production business recorded expenses of $16.1 million in 2007, $10.8 million in 2006 and $9.6 million in 2005 for accretion on discounted abandonment liabilities. 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. The higher accretion costs in 2007 were mostly related to higher estimated future abandonment costs for facilities and wells in the Gulf of Mexico and future abandonment obligations related to additional development wells drilled in the Kikeh field in 2007. The higher accretion costs incurred in 2006 were also mostly associated with development wells drilled at the Kikeh field in the prior year.
The effective income tax rate for exploration and production operations was 34.6% in 2007, 36.1% in 2006 and 39.1% in 2005. Both 2007 and 2006 included net tax benefits due to enacted changes in foreign tax rates. Canada lowered federal tax rates in both years and in 2006 the Canadian provinces of Alberta and Saskatchewan also lowered tax rates. The net benefit from these Canadian tax rate reductions, which effectively reduced recorded deferred tax liabilities was $38.7 million in 2007 and $37.5 million in 2006. A U.K. tax rate increase from 40% to 50% on oil and gas profits in 2006 increased taxes in the prior year by $17.8 million. The effective tax rate in 2007 was slightly below the U.S. statutory tax rate of 35% primarily due to the enacted Canadian tax rate reduction during the year. The 2007 effective tax rate was lower than in 2006 mostly due to the charge in 2006 related to the U.K. tax rate increase. A benefit for a charitable building donation based on fair value reduced U.S. taxes by $4.4 million in 2007. Also in 2007, the Company incurred lower exploration and other expenses in tax jurisdictions where tax relief is currently not available. These tax jurisdictions with no current tax benefit on expenses primarily include non-revenue generating areas in Malaysia, the Republic of Congo and Indonesia. Each main exploration area in Malaysia is currently ring-fenced and no tax benefits have thus far been recognized for costs incurred for Blocks H, P, L and M, offshore Sabah, and Blocks PM 311/312, offshore Peninsula Malaysia. Although the 2006 effective tax rate was only slightly higher than the U.S. statutory tax rate of 35%, the annual rate was lower than in 2005 mostly due to net benefits from the aforementioned tax rate changes. The effective tax rate in 2005 was higher than the average U.S. statutory rate due to unrecognized income tax benefits on certain exploration and other expenses in Malaysia and the Republic of Congo.
At December 31, 2007, approximately 39% of the Companyâ€™s U.S. proved oil reserves and 38% of the U.S. proved natural gas reserves are undeveloped. Virtually all of the total U.S. undeveloped reserves (on a barrel of oil equivalent basis) are associated with the Companyâ€™s various deepwater Gulf of Mexico fields. Further drilling, facility construction and well workovers are required to move undeveloped reserves to developed. In Block K Malaysia, 42% of both oil and natural gas reserves of 61.2 million barrels and 107.1 billion cubic feet, respectively, at year-end 2007 for the Kikeh field are undeveloped pending completion of facilities and continued development drilling, and 100% of the 14.8 million barrels of oil reserves at the Kakap field are undeveloped pending completion of drilling operations directed by another company. Also in Malaysia, there were 317.0 billion cubic feet of undeveloped natural gas reserves at various fields offshore Sarawak at year-end 2007, pending completion of development drilling and facilities. First gas production at the Kikeh field is scheduled for the second half of 2008 and at Sarawak fields in early 2009. On a worldwide basis, the Company spent approximately $769 million in 2007, $560 million in 2006 and $378 million in 2005 to develop proved reserves. The Company expects to spend about $1,061 million in 2008, $495 million in 2009 and $474 million in 2010 to move currently undeveloped proved reserves to the developed category.
Refining and Marketing â€“ The Companyâ€™s refining and marketing (R&M) operations generated record earnings of $205.7 million in 2007, after earning $110.6 million in 2006 and $131.6 million in 2005. The 86% improvement in R&M earnings in 2007 compared to 2006 was due to stronger refining margins in the U.S., lower hurricane-related expenses in 2007, and a fully operational Meraux refinery which was shut-down for repairs for about five months in 2006 following Hurricane Katrina. Total hurricane expenses after taxes in R&M operations were $1.9 million in 2007, $67.1 million in 2006 and $28.7 million in 2005. The Meraux, Louisiana refinery significantly increased crude oil throughputs in 2007 compared to 2006, which was unfavorably affected by downtime for repairs. R&M earnings in 2007 were net of two significant charges â€“ a $24.5 million after-tax charge related to closure of 55 gasoline stations in the U.S. and Canada, and an after-tax inventory charge of $59.5 million in the U.K.
The 16% decline in earnings in 2006 compared to 2005 was primarily due to hurricane related after-tax costs of $67.1 million and lower crude oil throughput volumes at the Meraux, Louisiana refinery. In late August 2005, the Meraux refinery experienced severe flooding and wind damage associated with Hurricane Katrina and was shut down from late August 2005 through mid-2006. The hurricane related costs in 2006 were partially offset by stronger refining margins generated by the Superior, Wisconsin refinery and continued growth in the Companyâ€™s North American retail gasoline marketing activities.
The Companyâ€™s North American R&M operations generated earnings of $230.4 million in 2007, $77.5 million in 2006 and $91.1 million in 2005. North American operations include refining activities in the United States and marketing activities in the United States and Canada. The 2006 and 2005 operating results for the Companyâ€™s North American refining business were negatively impacted by hurricane-related costs and below optimal Meraux refinery crude throughput volumes as a result of Hurricane Katrina. Uninsured damages, higher insurance premiums, settlement of the class action oil spill litigation and other hurricane-related pretax costs in the Companyâ€™s North American operations were $3.0 million in 2007, $107.3 million in 2006 and $46.3 million in 2005. The 2007 hurricane costs were caused by a downward adjustment of expected insurance recoveries based on the latest loss limits published by the Companyâ€™s primary insurer. The Meraux refinery throughput volumes of crude oil and other feedstocks averaged 112,840 barrels per day in 2007, 57,198 barrels per day in 2006 and 75,443 barrels per day in 2005. Significant flooding and wind damage associated with Hurricane Katrina resulted in the refinery being shut down from late August 2005 through May 2006. During the refineryâ€™s nine months of downtime for repairs, major upgrades and improvements were completed, and turnarounds on the refineryâ€™s hydrocracker and fluid catalytic cracking unit debutanizer were performed. The Companyâ€™s refinery in Superior, Wisconsin generated strong earnings in 2007 and 2006 as a result of steady operations and the continued strength of industry refining margins in North America. The operating results for the Companyâ€™s North American retail gasoline stations were lower in 2007 compared to the prior year as 55 underperforming stores were closed during the just completed year, including 47 in the U.S. and all eight stations in Canada. The Company recorded an impairment charge of $38.2 million in 2007 associated with these store closures. Excluding this impairment charge, the 2007 operating results for this business would have been essentially flat with 2006. A total of 33 new retail stations were opened in 2007, including 31 in the parking lots of Wal-Mart Supercenters and two at other locations. Average fuel sales per station increased again in 2007, the 10th straight year of improvements. The Companyâ€™s operating results in 2006 for North American retail operations were similar to 2005, and 2006 was highlighted by higher average fuel and non-fuel sales volumes compared to 2005 as well as continued additions to the number of stations in operation. Retail fuel sales volumes increased 22% in 2006 compared to 2005. The Company added 123 Murphy USA fueling stations in 2006, a 14% increase in the number of sites at year-end 2006 compared to 2005.
Unit margins (sales realization less costs of crude and other feedstocks, transportation to point of sale and refinery operating and depreciation expenses) averaged $4.28 per barrel in North America in 2007, $3.48 in 2006 and $2.96 in 2005. North American refined product sales volumes increased 19% to a record 416,668 barrels per day in 2007, following a 9% increase to 350,601 barrels per day in 2006. The Companyâ€™s U.S. retail gasoline stations continued to increase per site fuel sales volumes with a 4% increase in the average monthly fuel sales volume per station in 2007 following a 6% increase in 2006.
Operations in the United Kingdom reported a loss of $24.7 million in 2007 compared to earnings of $33.1 million in 2006 and $40.5 million in 2005. On December 1, 2007, the Company acquired the remaining 70% of the Milford Haven, Wales refinery that it did not already own. In association with this acquisition, the Company built a significant additional layer of crude oil and refined products inventory. The 2007 loss included a $59.5 million after-tax non-cash charge to reduce the carrying value of these higher inventory levels to early 2007 prices. Under the Companyâ€™s last-in-first-out (LIFO) inventory accounting policy, inventory volume increases are priced at the first purchase prices during the year, and the prices of crude and refined products were at a much lower level in early 2007 compared to the price at the time these products were acquired near year-end 2007. After the LIFO charge, the average go-forward carrying value for these additional inventories in the U.K. has been reduced by approximately $40 per barrel. Excluding this non-cash inventory charge, the 2007 operating result for the Companyâ€™s U.K. operations was slightly improved over 2006. The decrease in 2006 U.K. earnings compared to 2005 was due primarily to lower refinery margins as a result of higher operating and transportation costs in 2006 and nonrecurring credits in 2005 for property tax rebates and insurance settlements. The decline in refinery earnings in 2006 was partially offset by stronger marketing margins and higher marketing sales volumes as a result of the contribution from 68 retail sites acquired in 2005.
Unit margins in the United Kingdom averaged $0.22 per barrel in 2007, $6.39 per barrel in 2006 and $6.36 per barrel in 2005. Overall sales of refined products in the U.K. increased 19% in 2007, following a decline of 2% in 2006. The 2007 sales increase was mostly attributable to additional quantities of refined products produced after the Milford Haven acquisition. The decline in 2006 sales volumes was primarily due to lower demand for refined products based on higher average sales prices.
Corporate â€“ The after-tax costs of corporate activities, which include interest income, interest expense, foreign exchange gains and losses, and corporate overhead not allocated to operating functions, were $96.3 million in 2007, $82.7 million in 2006 and $35.5 million in 2005. Net corporate costs increased $13.6 million in 2007 compared to 2006 due primarily to higher net interest expense and higher losses on foreign exchange. These higher costs were partially offset by lower costs in 2007 associated with an educational assistance commitment. Net interest expense rose by $16.1 million in 2007 compared to 2006 due to interest associated with higher average outstanding long-term debt balances. The Companyâ€™s borrowings increased due to higher capital spending on oil and natural gas development projects in Malaysia, the Republic of Congo and Canada, and in the downstream business related to capital spending for the purchase of the Milford Haven, Wales refinery and land underlying most gasoline stations at Wal-Mart sites. The amount of interest capitalized to development projects increased in 2007 in association with higher capital development spending. The after-tax effect of foreign exchange was a charge of $13.8 million in 2007 compared to $7.9 million in 2006. The U.S. dollar weakened in 2007 by 17% against the Canadian dollar, 11% against the Euro and 2% against the British pound sterling. Administrative expenses in 2007 in the corporate area were $20.3 million less than 2006 due mostly to lower costs associated with the El Dorado Promise educational assistance contribution, but partially offset by higher compensation costs in the current year. The El Dorado Promise involves the Companyâ€™s commitment to contribute $5.0 million per year through 2016 to pay for post-secondary tuition for eligible graduates of El Dorado High School in Arkansas. Income taxes were unfavorable in the corporate area in 2007 compared to 2006 due to a higher portion of interest and administrative expenses allocable to foreign operations without current tax relief.
Net corporate costs were $47.2 million higher in 2006 than 2005 primarily due to a $25.1 million after-tax cost recorded in 2006 for the El Dorado Promise, unfavorable foreign exchange impacts and lower income tax benefits in 2006. The U.S. dollar weakened by 14% against the British pound sterling and 12% against the Euro during 2006, but the exchange rate against the Canadian dollar was not significantly different in 2006 compared to 2005. The after-tax effect of the weaker U.S. dollar in 2006 was a charge of $7.9 million, while the foreign exchange effect on 2005 was insignificant. The 2005 corporate results included $9.7 million of income tax benefits due to refund and settlement of prior year U.S. income tax matters. Interest income was higher by $4.9 million in 2006 mostly due to interest collected on favorable settlements of prior-year lawsuits and other disagreements with partners on E&P projects in Ecuador and western Canada. Administrative expenses in the corporate area were $40.2 million higher in 2006 mostly due to the educational assistance commitment, plus higher costs associated with initial recognition of the grant-date fair value of stock options beginning in 2006. These higher administrative expenses were partially offset in 2006 by lower other incentive compensation costs. Interest expense was $5.2 million higher in 2006 mostly due to higher average outstanding borrowings under credit facilities. The portion of interest capitalized to development projects increased by $4.5 million in 2006 due mostly to higher capital spending on Kikeh field development, offshore Sabah, Malaysia, and for field development in the Gulf of Mexico, partially offset by lower interest capitalized on the expansion at Syncrude.
As shown in the selected financial data on page 13 of this Form 10-K report, capital expenditures, including exploration expenditures, were $2,357.3 million in 2007 compared to $1,262.5 million in 2006 and $1,329.8 million in 2005. These amounts included $169.9 million, $196.7 million and $209.6 million, respectively, in 2007, 2006 and 2005 for exploration costs that were expensed. Capital expenditures for exploration and production activities totaled $1,780.7 million in 2007, $1,082.8 million in 2006 and $1,092.0 million in 2005, representing 76%, 86% and 82%, respectively, of the Companyâ€™s total capital expenditures for these years. E&P capital expenditures in 2007 included $422.6 million for acquisition of undeveloped leases, primarily in the Tupper area of northeastern British Columbia, $205.7 million for exploration activities, and $1,152.4 million for development projects. Development expenditures included $183.5 million for deepwater fields in the Gulf of Mexico; $512.2 million for the Kikeh field in Malaysia; $69.4 million for natural gas and other development activities in SK Blocks 309/311; $23.6 million for synthetic oil operations at the Syncrude project in Canada; $96.9 million for western Canada heavy oil and natural gas projects; $129.3 million for development of the Azurite field in the Republic of Congo; $26.5 million for the Terra Nova and Hibernia oil fields, offshore Newfoundland; $31.2 million for fields in the U.K. North Sea; and $40.1 million for development of Block 16 in Ecuador. Exploration and production capital expenditures are shown by major operating area on page F-37 of this Form 10-K report.
Refining and marketing capital expenditures totaled $572.5 million in 2007, $173.4 million in 2006 and $202.4 million in 2005. These amounts represented 24%, 14% and 15% of capital expenditures of the Company in 2007, 2006 and 2005, respectively. Refining capital spending was $330.0 million in 2007 compared to $57.3 million in 2006 and $34.1 million in 2005. The 2007 refining capital included $240.7 million for acquisition of the remaining 70% of the Milford Haven, Wales refinery. Most of the remaining refinery capital in 2007 was related to property acquired surrounding the Meraux, Louisiana refinery. The bulk of the refining capital in 2006 was spent at the Meraux, Louisiana refinery where numerous capital improvements were completed while the plant was shut-down for repairs following Hurricane Katrina. Marketing expenditures amounted to $242.5 million in 2007, $116.1 million in 2006 and $168.2 million in 2005. The capital spending in 2007 was mostly attributable to acquisition of land underlying retail gasoline stations located at Wal-Mart Supercenters. The majority of marketing expenditures in 2006 and 2005 was related to construction of retail gasoline stations at Wal-Mart Supercenters in the U.S. The Company opened 33 new stations within this network in 2007, after adding 123 in 2006 and 112 in 2005. In 2005, the Company also purchased 68 retail fueling stations in the U.K., thereby expanding its company-owned retail station count in that country by 70%.
Cash provided by operating activities was $1,740.4 million in 2007, $975.5 million in 2006 and $1,248.9 million in 2005. Cash provided by operating activities in 2007 was approximately $765 million more than in 2006 mostly due to a combination of higher net income, higher depreciation, impairment and deferred tax expenses, and a reduction of noncash operating working capital in 2007 versus an increase in 2006. Cash provided by operating activities in 2006 was about $273 million lower than in 2005 and was unfavorably affected by higher spending in 2006 for inventories, prepaid insurance, and repair costs at the Meraux refinery. In addition, 2006 cash provided by operating activities was unfavorably affected by lower oil and natural gas sales volumes and higher operating costs associated with repairs of oil and gas production facilities. Cash provided by operating activities in 2005 included $8.6 million from discontinued operations. Cash provided by operating activities was reduced by expenditures for abandonment of oil and gas properties totaling $13.0 million in 2007, $3.3 million in 2006 and $8.3 million in 2005.
Cash proceeds from property sales were $21.6 million in 2007, $23.8 million in 2006 and $172.7 million in 2005. The sales proceeds in 2007 and 2006 primarily related to sales of various properties, real estate and aircraft. The 2005 sales proceeds were mostly attributable to sale of most oil and gas properties on the continental shelf of the Gulf of Mexico; the Company retained its deepwater Gulf of Mexico properties. During 2007 and 2006, the Company borrowed $686.2 million and $237.7 million, respectively, under notes payable primarily to fund a portion of the Companyâ€™s development capital expenditures. Cash proceeds from stock option exercises and employee stock purchase plans, including certain income tax benefits on stock options classified as financing activities, amounted to $72.4 million in 2007, $36.6 million in 2006 and $26.5 million in 2005. Maturity of U.S. government securities provided cash of $17.9 million in 2005.
MANAGEMENT DISCUSSION FOR LATEST QUARTER
Results of Operations
Murphyâ€™s net income in the third quarter of 2008 was $584.4 million, $3.04 per diluted share, compared to net income of $199.5 million, $1.04 per diluted share, in the third quarter of 2007. The higher income in 2008 primarily related to improved earnings in both the Companyâ€™s exploration and production and refining and marketing businesses, partially offset by higher net costs for corporate activities.
For the first nine months of 2008, net income totaled $1.613 billion, $8.39 per diluted share, compared to net income of $560.4 million, $2.94 per diluted share, for the same period in 2007. The higher nine-month income in 2008 compared to 2007 was primarily attributable to higher earnings in the exploration and production business, partially offset by weaker earnings for refining and marketing operations and higher net corporate costs.
In the 2008 third quarter, the Companyâ€™s exploration and production operations earned $529.9 million compared to $150.8 million in the 2007 quarter. Income in the 2008 quarter was favorably affected by higher crude oil and natural gas sales prices and higher crude oil sales volumes. Exploration expenses were $83.4 million in the third quarter of 2008 compared to $42.5 million in the same period of 2007. The Companyâ€™s refining and marketing operations generated income of $85.8 million in the 2008 third quarter compared to income of $73.2 million in the same quarter of 2007. The third quarter 2008 benefited from much stronger U.S. retail marketing margins compared to 2007, but refining margins in the U.S. and U.K. were significantly weaker in the 2008 period. The after-tax costs of the corporate function were $31.3 million in the 2008 third quarter compared to $24.5 million in the 2007 period with the cost increase due to higher net interest costs and larger foreign exchange losses in 2008.
For the nine months of 2008, the Companyâ€™s exploration and production operations earned $1.535 billion compared to $388.9 million in the 2007 period. Earnings in 2008 benefited from significantly higher realized oil sales prices, higher oil sales volumes, and gains on sale of assets. The Companyâ€™s refining and marketing operations had earnings of $173.3 million in the first nine months of 2008, compared to earnings of $233.1 million in the same 2007 period. The 2008 period included lower earnings in the North American downstream business compared to a year ago, primarily caused by significantly weaker refining margins in 2008, but partially offset by stronger margins in U.S. retail marketing operations. Earnings from downstream operations in the U.K. improved in 2008 compared to 2007 due to better margins in refining operations and higher sales volumes due to the acquisition of the remaining 70% interest in the Milford Haven refinery in December 2007. Corporate after-tax costs were $95.8 million in the 2008 period compared to costs of $61.6 million in the 2007 period. Higher net interest expense, unfavorable foreign currency exchange results and higher administrative expenses accounted for the higher net costs in 2008.
United States exploration and production operations reported quarterly earnings of $41.0 million in the third quarter of 2008 compared to earnings of $24.8 million in the 2007 quarter. U.S. earnings were higher in the 2008 period due mostly to higher oil and natural gas sales prices. Lower U.S. oil production volumes and lower natural gas sales volumes were mostly attributable to production shut-in in the Gulf of Mexico associated with Hurricanes Gustav and Ike. Depreciation expense in the U.S. was higher in 2008 primarily due to higher per-unit depletion rates. U.S. exploration expenses in the 2008 period increased $11.3 million from the prior year primarily due to higher dry hole costs and higher leasehold amortization, somewhat offset by lower geological and geophysical expenses. Selling and general expenses in the U.S. were lower in the 2008 period than in 2007 due to a real estate donation in the prior year.
Operations in Canada earned $166.8 million in the third quarter 2008 compared to $107.1 million in the 2007 quarter. Canadian earnings improved in the 2008 quarter mostly due to higher oil sales prices. Oil production and sales volumes declined in the 2008 period compared to 2007 primarily due to less oil produced offshore Eastern Canada and in the heavy oil area of Western Canada. Natural gas sales volumes declined in 2008 mostly due to sale of Berkana Energy in January 2008. Depreciation expense was lower in 2008 due to less oil and natural gas production and sales of properties. Exploration expense was $10.0 million higher in the 2008 period due to more lease amortization expense attributable to the Tupper natural gas area in British Columbia, but partially offset by lower dry hole and geophysical expenses. The 2007 quarter included $8.3 million in income tax benefits related to adjustments of estimated prior-period taxes.
United Kingdom operations earned $20.5 million in the 2008 quarter, up from $11.0 million in the 2007 quarter. The 2008 improvement was primarily due to higher crude oil and natural gas sales prices in the current quarter. In addition, the 2008 quarter included higher U.K. crude oil and natural gas sales volumes. Production and depreciation expenses were higher in the 2008 period in the U.K. primarily due to the increase in crude oil and natural gas sales volumes.
Operations in Malaysia reported earnings of $308.3 million in the 2008 quarter compared to earnings of $4.3 million during the same period in 2007. The earnings improvement in 2008 in Malaysia was primarily due to higher crude oil sales volumes caused by the continued ramp-up of production during 2008 at the Kikeh field. Kikeh came on production in the third quarter of 2007, but the first sale from this field occurred in the fourth quarter of 2007. Production and depreciation expenses were higher in Malaysia in the current period also due to higher sales volumes. Malaysian exploration expense was higher in 2008 due to an unsuccessful exploration well in Block K. Selling and general expense in Malaysia was lower in the 2008 period due to higher charges to production and development operations under the joint operating agreement at Kikeh.
Operations in Ecuador resulted in a net loss of $0.6 million in the third quarter of 2008 compared to a profit of $10.3 million in the 2007 period. The 2008 results were unfavorable primarily due to a combination of lower realized oil sales prices caused by higher revenue sharing taken by the Ecuadorian government in the 2008 quarter, lower crude oil sales volumes, and an unfavorable income tax adjustment in 2008 related to the prior year. Beginning in mid- October 2007, the government of Ecuador claimed 99% of crude oil sales prices that exceeded a benchmark price, which was approximately $24.31 per barrel in September 2008. Prior to this change, the governmentâ€™s revenue sharing was 50% of realized prices that exceeded the benchmark price. Production expense in Ecuador was lower in 2008 due to less crude oil sales volumes. See page 25 for further discussion regarding Ecuador.
Other international operations reported a loss of $6.1 million in the third quarter of 2008 compared to a loss of $6.7 million in the 2007 period. The favorable variance was primarily related to slightly lower administrative costs in the 2008 quarter.
On a worldwide basis, the Companyâ€™s crude oil, condensate and natural gas liquids prices averaged $107.98 per barrel in the third quarter 2008 compared to $63.96 per barrel in the 2007 period. Average oil and gas liquids production was 118,797 barrels per day in the third quarter of 2008 compared to 87,962 barrels per day in the third quarter of 2007, with the increase primarily attributable to ramp-up of production at the Kikeh field in Malaysia during the 2008 period. Crude oil production was lower in the U.S. in 2008 mostly due to shut-in of Gulf of Mexico fields caused by two hurricanes during the third quarter. Certain offshore oil and natural gas production remained shut-in during October and early November 2008. There was no Canadian light oil production in the 2008 third quarter due to sale of the Companyâ€™s interest in Berkana Energy in January 2008. Canadian heavy oil production was lower in the 2008 quarter compared to 2007 due to sale of the Lloydminster area properties during the second quarter of 2008. Canadian offshore crude oil production fell in 2008 due to a production decline at the Hibernia field and more equipment downtime and a higher royalty rate at the Terra Nova field. Ecuador oil production was lower in 2008 due to less drilling activity in Block 16 following the increase in the government revenue share in October 2007. North American natural gas sales prices averaged $11.51 per thousand cubic feet (MCF) in the most recent quarter compared to $6.22 per MCF in the same quarter of 2007. Natural gas sales volumes averaged 46 million cubic feet per day in the third quarter 2008, down from 56 million cubic feet per day in the 2007 quarter, due to a combination of lower volumes in Canada caused by the sale of Berkana Energy in January 2008 and Gulf of Mexico fields shut-in during the third quarter of 2008 due to two hurricanes during the period. Natural gas sales volumes increased in the U.K. in 2008 primarily due to higher volumes sold from the Amethyst and Mungo/Monan offshore fields.
The sales prices for crude oil and natural gas have declined significantly in the fourth quarter 2008 compared to the average prices in the third quarter and for the first nine months of 2008.
Nine months 2008 vs. 2007
U.S. E&P operations produced income of $159.5 million for the nine months ended September 30, 2008 compared to income of $59.3 million in the 2007 period. The 2008 period had higher oil and natural gas sales prices and higher natural gas sales volumes, but lower crude oil sales volumes. Production expenses in the U.S. were lower in 2008 mostly due to less costs for workovers and other field maintenance. U.S. depreciation expense was unfavorable in 2008 due to higher per-unit depletion rates compared to 2007. Exploration expenses in the 2008 period in the U.S. were $2.0 million lower than 2007 due to less dry holes expense in 2008, but partially offset by higher geological and geophysical and leasehold amortization expenses in 2008.
Canadian operations earned $554.5 million in the 2008 period compared to $263.6 million a year ago. Higher sales prices for crude oil and natural gas and after-tax gains of $108.3 million on sales of properties primarily led to the increase in earnings. Higher Canadian production expenses in 2008 were mostly related to higher energy costs at Syncrude. Lower depreciation expense in 2008 in Canada was attributable to less oil and natural gas volumes produced and sold. Exploration expenses in Canada were $58.3 million higher in 2008 primarily due to more seismic costs and higher undeveloped lease amortization for new acreage acquired at the Tupper field in British Columbia, but these were partially offset by lower dry hole expense during 2008.
Income in the U.K. for the nine-month period in 2008 was $67.0 million compared to $37.9 million a year ago, with the increase primarily due to higher oil and natural gas sales prices and higher natural gas sales volumes, partially offset by lower crude oil sales volumes.
Malaysia operations earned $776.4 million in the first nine months of 2008 compared to earnings of $29.2 million in the 2007 period. The earnings improvement was primarily caused by crude oil sales volumes associated with the Kikeh field, offshore Sabah, which commenced production in the third quarter of 2007. Production at Kikeh increased during 2008 as more wells came on stream. Average crude oil sales prices were also significantly higher in 2008 than in 2007. Production and depreciation expenses in Malaysia were significantly higher and were related to the increase in Kikeh field production. Malaysian exploration expense was higher in 2008 mostly due to more costs for unsuccessful exploration drilling during 2008. Selling and general expense in Malaysia declined in 2008 due to higher levels of costs charged to production and development operations.
Earnings in Ecuador were $0.9 million for the first nine months of 2008 compared to $24.3 million for the 2007 period. The earnings decline in 2008 was due to higher revenue sharing with the government for sales prices above a benchmark price. In addition, crude oil production and associated sales volumes were lower in 2008 due to less spending on development drilling following the increase in government revenue sharing that took effect in October 2007. See page 25 for further discussion regarding Ecuador.
Other international operations reported a loss of $23.2 million in the first nine months of 2008 compared to a loss of $25.4 million in the 2007 period. The smaller loss in the 2008 period was primarily due to lower geophysical expenses in the Republic of Congo, but partially offset by higher costs in 2008 for exploration and administrative activities in other foreign jurisdictions.
For the first nine months of 2008, the Companyâ€™s sales price for crude oil, condensate and natural gas liquids averaged $100.53 per barrel compared to $56.10 per barrel in 2007. Crude oil, condensate and gas liquids production in the first nine months of 2008 averaged 114,559 barrels per day compared to 84,169 barrels per day a year ago. The increase was mostly attributable to Kikeh field production, offshore Malaysia, which continued to ramp up during 2008, but production volumes were lower in the Gulf of Mexico mostly caused by shut-in of fields due to third quarter hurricanes. Production in the heavy oil area of Western Canada was lower mostly due to the sale of the Lloydminster property in the second quarter 2008. Oil production was lower at the West Patricia field, offshore Sarawak, Malaysia, due to both field decline and a lower percentage of production allocable to the Company under the production sharing contract. The average sales price for North American natural gas in the first nine months of 2008 was $10.27 per MCF, up from $7.16 per MCF in 2007. Natural gas sales volumes in 2008 were 57 million cubic feet per day compared to 58 million cubic feet per day in 2007, with the decrease due mostly to wells shut-in by two hurricanes in the third quarter 2008. Lower natural gas volumes in Canada were caused by the sale of the Companyâ€™s interest in Berkana Energy in January 2008.
Thank you and good afternoon. I am joined today by Kevin Fitzgerald, Senior VP and Chief Financial Officer, John Eckard, VP and Controller, Mindy West, VO and Treasurer, and Dory Stiles, Manager of Investor Relations.
I will turn it over to Dory at this time.
Thanks Claiborne, and welcome everyone and thank you for joining us today. Our call will follow our usual format today with Kevin beginning by providing a review of third quarter 2008 results, Claiborne will then follow with an operational update, after which we will take your questions. Please keep in mind that some of the comments made during this call will be considered forward looking statements, as such no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. Many of these have been identified as Murphyâ€™s January 1997 form 8-K filed with the SEC. I will now turn the call over to Kevin for his remarks.
Net income for the third quarter of â€™08 was $584.4 million or $3.04 per diluted share, and that compares to third quarter of â€™07, where we had net income of $199.5 million, or $1.04 per diluted share.
For nine months of â€™08, net income was just over $1.6 billion, or 8.39 per share, and that compares to net income for nine months of â€™07 of $560.4 million, or 2.94 per diluted share.
2008 nine month period includes after tax gains from the sales of Canadian assets, our interest in Berkana Energy, and Lloydminster heavy oil properties that both occurred this earlier this year, about 108.3 million or $0.57 a share. The 2007 nine month period includes after tax cost of 24 million or about $0.13 a share, and this was related to the closure of 55 retail gasoline stations in the US and Canada.
Looking at income by segment, first the EMP for third quarter of â€™08, income was 529.9 million, and that compares to 150.8 million of net income third quarter of â€™07. Higher earnings for the â€™08 quarter were primarily attributable to higher crude oil price realizations and higher oil sale volumes.
Crude oil and gas liquids production for the current quarter was a little over 118 thousand barrels per day, as compared to 88 thousand barrels per day in the corresponding 2007 quarter. Increase was primarily attributable to production in Kikeh, offshore Malaysia, which started up in the third quarter of â€™07, but this was partially offset by lower volumes in the US as a result of field shut-ins due to the Hurricanes Gustav and Ike.
Also, lower volumes of Canadian heavy oil due to the sale of the Lloydminster properties in the second quarter of this year, and lower buy-ins from Terra Nova field offshore Eastern Canada.
Natural gas sales volumes were 46 million cubic feet per day in the third quarter of â€™08, compared to 56 million feet per day in third quarter of last year. This decrease was primarily due to field shut-ins in the Gulf for the hurricanes, and the sale of Berkana Energy in Canada early this year.
The R&M segment third quarter of â€™08, net income was 85.8 million, compared to 73.2 million of net income third quarter of last year. The earnings increase was all in the US and primarily due to better marketing margins, while results in the UK were slightly below break even due to weaker refining margins.
The corporate segment third quarter of â€™08, we had net charges of 31.3 million, compared to net charges of 24.5 million in third quarter of last year. This cost increase was attributable to a combination of higher net interest expense due to lower amounts being capitalized to development projects and higher foreign exchange losses.
As of September 20, 2008, Murphyâ€™s loan term debt was a bit less than 1.1 billion, or about14.1% of total capital employed.
And with that Iâ€™ll turn it over to Claiborne.
Thanks Kevin. Before going into the operational update, I thought I would spend a minute addressing where Murphyâ€™ stands in the economic and capital market environment that has emerged since we spoke last quarter.
As Kevin touched on, our company is financially quite strong with low leverage. A 14% debt to total cap ratio, over $1.4 billion of cash and short term marketable securities on hand, continued access to capital funds.
We will continue to concentrate on the things that are within our control and go about managing our business as usual, while being keenly aware and ready to act on opportunities that arise. We are currently working on next yearâ€™s capital budget, and while not ready to discuss in detail, I will say that we will optimize expenditures to ensure that we maintain our financial flexibility.
Now, I will update you on the current activities within our E&P business, and then move to downstream. First exploration for the first oil wells have now been drilled in the Eastern Gulf of Mexico. Two of these were natural gas discoveries, diamond, and oil rich 370 in Dalmation in De Soto Canyon 48. Both will be developed as subsidy tie-backs.
The (inaudible 1:03) confidence rig has now moved to Finger Hawk for development work. In the first quarter of 2009, we will start a non-operated wild cat called Samurai in Grand Canyon 432-476, in which we hold a one-third interest. This prospect is on acreage that we picked up on early this year, the central sale 2006.
Offshore Malaysia, the Ocean Rover rig, will move over to Block P to drill an oil prospect called Chengal, 60% working interest, late this year following completion of the current phase of development work at Kikeh.
Exploration offshore sale rack, 60% working interest, continues following a recent dry hole at Sabahtan. Two more holes will be drilled in the coming months.
In Australia, in this quarter, we planned to sprout our first well at Abalone Deep, where we have a 40% working interest. The multi TCF liquids rich natural gas prospect, Brows Basin Block ACT36.
Turning to production, the US Gulf of Mexico continues to recover from hurricanes Gustav and Ike. The platforms sustained only minor damage, but ongoing third party pipeline repairs have resulted in curtailed production during the months of September and October.
The third quarter impact to production is approximately 6000 barrel equivalents a day. The impact on the fourth quarter is estimated to be up to 7000 barrel equivalents a day, with all production on stream by the end of the quarter.
Elsewhere, the ramp up at Kikeh and Block K offshore Sabah, Malaysia continues according to plan with current production at 95,000 barrels per day. We will reach the plateau production rate of 120,000 barrels per day by the end of 2008, when three new producers are added.
Natural gas production will commence from Kikeh during the fourth quarter, with production volumes reaching 120 million cubic feet per day, once fully ramped up.
Over the next few months, four addition projects currently under development will becoming on stream first production from Phase one of Tupper, our tight sands gas resource play in British Columbia is scheduled to begin producing it in the next month, at an initial rate of 40 million cubic feet per day. We anticipate exiting the year at 65 million per day.
We now hold a total of 128 sections at Tupper. We have drilled five vertical wells in Tupper West, to better delineate the monotony in that large acreage block. So far, average thickness of monotony in this area is substantially improved over the current Tupper development area. In addition, three of these wells have been encountered a nicely developed dorg section, with pay, that is going to maturely enhance productions and returns in this area.
In Sarawak, Malaysia, work continues on phase one of our natural gas project, as it readies for first gas, now scheduled for the second quarter.
In the Gulf of Mexico, Thunder Hawk development is moving ahead. The fully submersible hull has arrived in the United Sates. During the loading process in Singapore, the hull sustained damage and is currently dry-docked while necessary repairs are made.
First production remains on track for 2Q â€™09 as originally planned. Meanwhile, in Azurite, where we have a 50% working interest, offshore the Republic of Congo, the first phase of sub-sea installation work is complete and the FDPSO is nearing completion. Initial production is scheduled for the end of the second quarter of 2009.
These projects will propel us to new successive production records in 2009, and 2010, and serve as nice complements to our existing base led by Kikeh.
Moving downstream, having a diversified US and international asset base once again proved important during the third quarter. While the UK segment was the to performer during the first half of the year, US retail led the way in the third quarter and has continued to do so in the fourth quarter. As crude oil prices have retreated, wholesale gasoline prices flowed, thus improving the margin environment for retail stations. Our high volume, low-cost model is ideally suited to trap profit in declining markets.
We currently have 1004 stations in operation, of which 984 are MurphyUSA sites, and 18 are the large Murphy Express convenience stores. They remain strong in our stations as year over year fuel and non-fuel sales are up.
In the US, weâ€™re finding margins are repressed at Meraux, due to extraordinarily weak gasoline crack spreads, while Superiorâ€™s margins are quite good. In addition, the planned 40 bay hydrocracker complex turnaround at Meraux was completed earlier this week and feed is currently being introduced back into the unit. Meraux was shut down for about 10 days during the third quarter for Hurricane Gustav.
UK refining margins have improved as of late following a weak third quarter. In UK retail, we have taken several steps to expand our footprint. In the third quarter we gained initial access into Scotland by purchasing two stations and leasing five others. This will allow us to gauge the marketplace for our products there. Just yesterday, we placed a deal covering sixty-three stations in England and Wales, 58 of which will be leased and five that will be purchased.
To wrap up, through the first three quarters of 2008, our results have been influenced by high commodity prices that have aided in setting net income records. Of course with fourth quarter, the oil markets have changed quite substantially as crude prices have dropped unusually fast. Except for the gut wrenching drop in the equity value of our company, this is a market we both understand and perversely like. Lower oil and natural gas prices are wonderful for our customers, and we were beginning to price ourselves out of the market, and handy for companies with ample liquidity that are underleveraged. As you know, we fit into that category.
As you also know, this is my last earnings conference call. On balance, I have enjoyed my relationship with the investment community during the 14-plus years I have been CEO of Murphy. You perform an extremely important role in disseminating information to our owners and potential owners, and as a result our style has been to tell it like it is, that will continue under my successor, David Wood.
Lastly, the energy markets that we are going through are actually more of the norm than of the exception. In my 30 years in this business, I suspect that around 25 of them have been involved with dealing with difficult markets. Ironically, we typically invest our shareholders money better during these periods because competition is more realistic, and pricing is better.
Our company is built to anticipate and prosper in these types of markets, and I expect this to continue as well.