Exhibit 99.2
| Item 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following management’s discussion and analysis should be read in conjunction with the Company’s historical consolidated financial statements, located herein as Exhibit 99.3 to this Current Report on Form 8-K and in Item 8. Financial Statements and Supplementary Data of our 2008 Annual Report on Form 10-K. Any references to Notes in the following management’s discussion and analysis refers to the Notes to Consolidated Financial Statements located in Exhibit 99.3 to this Current Report on Form 8-K and in Item 8. Financial Statements and Supplementary Data of our 2008 Form 10-K. The results of operations reported and summarized below are not necessarily indicative of future operating results. This discussion also contains forward-looking statements that reflect our current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, such as those set forth in Item 1A. Risk Factors, which can be found in our 2008 Form 10-K.
As further discussed in Note C, our consolidated financial statements for the periods presented herein have been adjusted to reflect the results of the Company’s Ecuador operations as discontinued operations. The financial information contained in management’s discussion and analysis below reflects the adjustments described in Note C. Except as discussed in “Subsequent Events” below and in Note C, no other modifications or updates to these disclosures for events occurring after February 27, 2009, the date of the filing of our 2008 Form 10-K, have been made in this Current Report on Form 8-K.
Subsequent Events
On March 12, 2009, the Company sold its operations in Ecuador for net cash proceeds of $78.9 million, subject to post-closing adjustments. The acquiror also assumed certain tax and other liabilities associated with the Ecuador properties sold. The Ecuador properties sold included 20% interests in producing Block 16 and the nearby Tivacuno area. Ecuador operating results prior to the sale have been reported as discontinued operations for all periods presented. The consolidated financial statements for 2008 and prior years have been adjusted to conform to this presentation.
Overview
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 Company’s significant assets can be found in Item 1 of the 2008 Form 10-K report filed with the Securities and Exchange Commission on February 27, 2009. As described in Note C to the consolidated financial statements, Murphy sold its interest in its Ecuador properties on March 12, 2009.
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 Company’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 production facilities, and gasoline is purchased to supply its retail gasoline stations in the U.S. that are primarily located at Walmart Supercenters, the purchase prices for these commodities also have a significant effect on the Company’s costs. In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products, amortization of capital expenditures and expenses related to exploration and administration. Profits and generation of cash in the Company’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.
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Worldwide oil and North American natural gas prices were significantly higher in 2008 than in 2007. The average price for a barrel of West Texas Intermediate crude oil in 2008 was $98.90, an increase of 37% compared to 2007. The NYMEX natural gas price in 2008 averaged $8.89 per million British Thermal Units (MMBTU), up 25% from 2007. Crude oil and natural gas prices generally rose during the first half of 2008 with oil prices reaching their high in July. Both crude oil and North American natural gas prices fell precipitously near the end of 2008 and remain soft in early 2009. 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 93% of the total hydrocarbons produced on an energy equivalent basis by the Company in 2008. In 2009, the percentage of hydrocarbon production represented by oil is expected to decline to about 78% due to new natural gas fields at Kikeh and Block SK 309 in Malaysia and Tupper in British Columbia. If the prices for crude oil and natural gas remain weak in 2009 or beyond, the Company would expect this to have an unfavorable impact on operating profits for its exploration and production business. Such lower oil and gas prices could, but may not, have a favorable impact on the Company’s refining and marketing operating profits.
Results of Operations
The Company had net income in 2008 of $1.74 billion, $9.06 per diluted share, compared to net income in 2007 of $766.5 million, $4.01 per diluted share. In 2006 the Company’s net income was $644.7 million, $3.41 per diluted share. The significant increase in 2008 net income compared to 2007 was caused by higher earnings in the exploration and production operations, primarily due to higher sales prices for the Company’s oil and natural gas production, higher crude oil production volumes and gains on disposal of two assets in Canada. The earnings for the Company’s refining and marketing operations were an annual record in 2008 and improved from 2007, primarily in the U.K. and mostly caused by the December 2007 purchase of 70% of the Milford Haven, Wales refinery. The net cost of corporate activities not allocated to the operating segments was higher in 2008 than in 2007. 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, but partially offset by higher net costs for corporate activities. Further explanations of each of these variances are found in the following sections. Income from continuing operations was $1.74 billion, $9.08 per diluted share, in 2008; $739.1 million, $3.87 per diluted share, in 2007; and $603.1 million, $3.19 per diluted share, in 2006.
2008 vs. 2007 – Net income in 2008 was $1.74 billion, $9.06 per diluted share, compared to $766.5 million, $4.01 per diluted share, in 2007. The consolidated net income improvement of $973.5 million in 2008 was attributable to higher earnings in both exploration and production (E&P) and refining and marketing (R&M) operations. The net cost of corporate activities in 2008 was higher than in 2007, partially offsetting the improved results in E&P and R&M. Earnings from continuing E&P operations were markedly improved in 2008, increasing by $974.2 million compared to 2007, as this business benefited from both higher sales prices for oil and natural gas, higher sales volumes for crude oil and gains from asset dispositions. E&P earnings were unfavorably affected in 2008 compared to 2007 by lower sales volumes for natural gas and higher expenses for exploration, production, depreciation, depletion and administration. The R&M business generated record profits in 2008, increasing $108.1 million compared to 2007. The improvement was primarily due to refining profits generated in the U.K. in the current year following the acquisition of the remaining 70% of the Milford Haven, Wales, refinery in December 2007. R&M earnings in 2007 included an unfavorable impact in the U.K. from noncash inventory revaluations. Following the Milford Haven acquisition, the Company’s U.K. operations recorded an after-tax noncash last-in, first-out accounting charge of $59.5 million 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 $76.6 million in 2008 compared to 2007, with the cost increase mostly attributable to higher losses on transactions denominated in foreign currencies and higher net expenses for interest and administration. The foreign currency losses occurred because the U.S. dollar generally strengthened against other significant foreign currencies used in the Company’s business in 2008, especially compared to the British pound sterling. The higher net interest expense was mostly caused by lower interest capitalized to E&P development projects. The 2008 period included higher corporate administrative costs mostly due to higher expense for employee compensation and community and other support activities.
Sales and other operating revenues were $9.1 billion higher in 2008 than in 2007 mostly due to higher sales prices and sales volumes for gasoline and other refined products, higher sales prices and sales volumes for crude oil produced by the Company, and higher revenues from merchandise sales at retail gasoline stations. Sales prices for natural gas were higher in 2008 than 2007, but the favorable price variance was somewhat offset by lower natural gas sales volumes in the current year. Gain/(loss) on sales of assets in 2008 was $134.1 million higher than in 2007 and these realized pretax gains were primarily associated with the sales of its interests in Berkana Energy and the Lloydminster area heavy oil properties in Canada. Interest and other income was lower by $77.7 million in 2008 due primarily to greater losses on foreign currency exchange, which in the current year was mostly attributable to a generally stronger U.S. dollar compared to the British pound sterling. Crude oil and product purchases expense increased by $6.8 billion in 2008 compared to 2007 due to a combination of higher purchase prices and throughput volumes of crude oil and other feedstocks at the Company’s refineries, higher prices and volumes of refined petroleum products purchased for sale at retail gasoline
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stations, and higher levels of merchandise purchased for sale at the gasoline stations. The higher crude oil purchase volumes in 2008 were caused by a full year of operations at the Milford Haven, Wales refinery in 2008 following the December 2007 purchase of the remaining 70% interest. Operating expenses increased by $382.6 million in 2008 compared to 2007 and included higher refinery and retail station costs, and higher costs for oil field operations in Malaysia and synthetic oil operations at Syncrude. Refining costs increased due to both higher natural gas and other fuel costs and the full year of operations at Milford Haven following the 2007 acquisition. Exploration expenses were $141.6 million higher in 2008 than in 2007 and were primarily associated with higher leasehold amortization expenses at the Tupper area in British Columbia, more dry hole expense in Malaysia and Australia, and higher geophysical expenses in Suriname. Exploration expenses in 2007 included costs for settlement of two work commitments on leases formerly held on the Scotian Shelf offshore eastern Canada. Selling and general expenses were $0.2 million higher in 2008 than in 2007. Depreciation, depletion and amortization expense was $216.6 million higher in 2008 compared to 2007 due mostly to higher crude oil production volumes, but also due to higher barrel-equivalent unit rates for depreciation for virtually all E&P segments and higher depreciation for the Milford Haven, Wales refinery acquired in December 2007. 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 $8.2 million in 2008 due to additional abandonment obligations incurred as additional Kikeh development wells were drilled during the year and higher estimated costs of future abandonment obligations at Syncrude. Net costs associated with hurricanes of $3.0 million in 2007 was due to a downward adjustment of anticipated insurance recoveries at the Meraux refinery following Hurricane Katrina based on updated loss limits communicated in 2007 by the Company’s primary property insurer. Interest expense incurred in 2008 was $1.1 million less than in 2007 due to lower average debt levels during 2008 compared to the prior year. The amount of interest costs capitalized to property, plant and equipment decreased by $18.4 million in 2008 due to lower levels of interest allocable to worldwide E&P development projects. Income tax expense was $623.7 million higher in 2008 than in 2007 and was mainly attributable to a higher level of pretax earnings. The effective income tax rate for consolidated earnings increased from 37.8% in 2007 to 38.1% in 2008. 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 of the uncertain ability of the Company to obtain tax benefits for these costs in future years. Loss from discontinued operations of $4.8 million in 2008 declined by $32.2 million compared to 2007 primarily due to a higher revenue sharing with the government of Ecuador. During 2008, the government required a 99% share of Block 16 realized sales prices that exceeded a benchmark price that escalates with the monthly U.S. Consumer Price Index. This government revenue sharing increased from 50% above the benchmark price to 99% in October 2007. At year-end 2008, the benchmark oil price for Block 16 was approximately $23.36 per barrel. The average realized sales price after revenue sharing with the Ecuadorian government for Block 16 oil was $27.83 per barrel during 2008, a decrease of 24% from 2007. The higher revenue sharing led to unprofitable operating results in 2008 for operations in Ecuador. The Company sold the Ecuador properties in March 2009.
2007 vs. 2006– 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 – E&P and R&M. 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 from continuing operations improved by $50.2 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 strong profits in 2007, increasing $95.1 million compared to 2006. The improvement was primarily due to higher 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 in the U.K. 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 Company’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 $9.3 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 Company’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.
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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 higher by $0.5 million in 2007 compared to 2006. 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 Company’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 for hurricane-related repairs in 2006. Operating expenses increased by $211.3 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 field operations in Malaysia and the U.K. and for Canadian synthetic oil operations at Syncrude. Exploration expenses were $15.0 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 leases formerly held in the Scotian Shelf. Selling and general expenses were $0.9 million higher in 2007 than in 2006 as higher compensation, insurance and Berkana Energy administrative costs in 2007 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 $93.9 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 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 $3.0 million of hurricane expense recorded in 2007 related to a downward adjustment of anticipated insurance recoveries at the Meraux refinery based on updated projected loss limits announced by the Company’s primary property insurer. Interest expense increased by $22.1 million in 2007 mostly associated with higher average debt levels 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 spending on E&P development projects in Malaysia, the U.S. and the Republic of the Congo. Income tax expense was $81.1 million higher in 2007 than in 2006 and was mainly attributable to higher pretax income levels. The effective income tax rate for consolidated earnings fell from 38.0% in 2006 to 37.8% 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 benefited, however, from overall favorable effects of tax rate changes in foreign countries. Income from discontinued operations of $27.4 million in 2007 was $14.2 million less than in 2006 primarily due to higher revenue sharing with the Ecuadoran government. For most of 2007, 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 2007, 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 2007 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. The Company sold its properties in Ecuador in March 2009.
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Segment Results – In the following table, the Company’s results of operations for the three years ended December 31, 2008 are presented by segment. More detailed reviews of operating results for the Company’s exploration and production and refining and marketing activities follow the table.
(Millions of dollars) | 2008 | 2007 | 2006 | |||||||
Exploration and production – Continuing operations | ||||||||||
United States | $ | 156.6 | 98.2 | 212.4 | ||||||
Canada | 588.7 | 370.2 | 330.6 | |||||||
United Kingdom | 73.8 | 47.6 | 60.7 | |||||||
Malaysia | 865.3 | 148.2 | (5.9 | ) | ||||||
Other | (81.6 | ) | (35.6 | ) | (19.4 | ) | ||||
| 1,602.8 | 628.6 | 578.4 | ||||||||
Refining and marketing | ||||||||||
North America | 227.9 | 230.4 | 77.5 | |||||||
United Kingdom | 85.9 | (24.7 | ) | 33.1 | ||||||
| 313.8 | 205.7 | 110.6 | ||||||||
Corporate and other | (171.8 | ) | (95.2 | ) | (85.9 | ) | ||||
Income from continuing operations | 1,744.8 | 739.1 | 603.1 | |||||||
Income (loss) from discontinued operations | (4.8 | ) | 27.4 | 41.6 | ||||||
Net income | $ | 1,740.0 | 766.5 | 644.7 | ||||||
Exploration and Production – Earnings from exploration and production continuing operations were $1.60 billion in 2008, $628.6 million in 2007 and $578.4 million in 2006. E&P earnings improved $974.2 million in 2008 compared to 2007 with the significant increase primarily due to higher average realized sales prices for the Company’s oil and natural gas production, higher crude oil production volumes and gains on disposals of Canadian assets. Results in 2007 were favorably impacted by income tax benefits associated with tax rate reductions in Canada. The 2008 results were unfavorably affected compared to 2007 by lower natural gas sales volumes and higher expenses for exploration, production, depreciation, depletion, administration and accretion of discounted abandonment liabilities. Crude oil sales volumes from continuing operations in 2008 were 49% higher than in 2007, compared with a 34% increase in crude oil production from continuing operations in 2008 compared to 2007. Crude oil sales volumes grew more than production in 2008 due to the timing of sale transactions as the Company had a lower inventory of unsold crude oil at year-end 2008 compared to a year earlier. The significant unsold crude oil inventory at year-end 2007 was mostly at Kikeh where sales volumes lagged production in late 2007 during the start-up phase of this field. During 2008, higher oil sales volumes in Malaysia attributable to higher production volumes at the Kikeh field were partially offset by lower oil sales volumes at most other producing areas. Lower U.S. crude oil sales volumes in 2008 were primarily due to reduced production volumes at several Gulf of Mexico fields following Hurricanes Gustav and Ike. Certain facilities owned by other companies downstream of our producing fields were down for repairs for an extended period of time in the fourth quarter 2008. Lower oil sales volumes in Canada were attributable to field decline at Hibernia, field decline and a higher royalty rate at Terra Nova, sale of the Lloydminster heavy oil property in Western Canada and more downtime at Syncrude. Lower crude oil sales volumes in the U.K. and at the West Patricia field, offshore Sarawak Malaysia, were mostly caused by production declines as these fields mature. Natural gas sales volumes were 9% lower in 2008 than 2007 and the reduction was mostly due to sale of Berkana Energy in January 2008. Additionally, several of the Company’s Gulf of Mexico fields were either shut in or had curtailed gas production while downstream facilities owned by others were repaired following third quarter hurricanes. The Company’s average realized oil sales price was 37% higher in 2008 than 2007, and the average North American natural gas sales price was 33% higher in 2008.
E&P earnings from continuing operations improved $50.2 million in 2007 compared to 2006 primarily due to higher average realized oil sales prices in the latter year for the Company’s production. In addition, exploration expenses were lower by $14.9 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 from continuing operations in 2007 were 2% lower than in 2006, despite a 4% increase in crude oil production from continuing operations 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 unsold crude oil inventory, which was primarily at the Kikeh field in Malaysia, returned to normal levels during 2008. During 2007, lower oil sales volumes in the U.S. 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. Higher oil sales volumes in Malaysia were mostly caused by start-up of the significant Kikeh field, offshore Sabah, in August 2007, partially offset by lower production at the West Patricia field, offshore Sarawak. Higher volumes in Canada were attributable to better
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production volumes at the Terra Nova field in the Jeanne d’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 Company’s average realized oil sales price was 21% higher in 2007 than 2006, while North American natural gas sales prices averaged 5% less in 2007 than in 2006.
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-39 and F-40 of this Form 8-K report. Average daily production and sales rates and weighted average sales prices are shown on page 10 which follows.
A summary of oil and gas revenues, including intersegment sales that are eliminated in the consolidated financial statements, is presented in the following table.
(Millions of dollars) | 2008 | 2007 | 2006 | ||||
United States | |||||||
Oil and gas liquids | $ | 374.0 | 310.8 | 440.1 | |||
Natural gas | 162.1 | 121.7 | 160.4 | ||||
Canada | |||||||
Conventional oil and gas liquids | 775.8 | 628.6 | 476.0 | ||||
Natural gas | 5.5 | 23.0 | 24.1 | ||||
Synthetic oil | 459.6 | 351.4 | 270.0 | ||||
United Kingdom | |||||||
Oil and gas liquids | 189.4 | 129.5 | 156.8 | ||||
Natural gas | 25.8 | 16.6 | 23.3 | ||||
Malaysia | |||||||
Oil and gas liquids | 1,985.6 | 436.0 | 219.6 | ||||
Natural gas | 0.1 | — | — | ||||
Total oil and gas revenues | $ | 3,977.9 | 2,017.6 | 1,770.3 | |||
The Company’s total crude oil, condensate and natural gas liquids production (including discontinued operations in Ecuador) averaged 118,254 barrels per day in 2008, 91,522 barrels per day in 2007 and 87,817 barrels per day in 2006. Production of crude oil, condensate and natural gas liquids in 2008 increased by 26,732 barrels per day, or 29% compared to 2007, primarily due to continued ramp-up of the Kikeh field in Block K, offshore Sabah, Malaysia. This prolific field, which came on production in August 2007 produced 53,000 net barrels of oil per day for the full-year 2008 compared to 11,658 barrels per day in 2007. Light oil production in Canada declined from 596 barrels per day in 2007 to 46 barrels per day in 2008 due to sale of Berkana Energy in January 2008. Heavy oil production in the Western Canadian Sedimentary Basin (WCSB) fell from 11,524 barrels per day in 2007 to 8,484 barrels per day in 2008, due to sale of the Lloydminster property in 2008 and lower production volumes at the Seal field in Alberta. Oil production at Hibernia, offshore Newfoundland, was 8,542 barrels per day in 2008, up slightly from 8,314 barrels per day in 2007. Oil production decreased at Terra Nova, offshore Newfoundland, from 10,557 barrels per day in 2007 to 8,284 barrels per day in 2008. The 2008 reduction at Terra Nova was attributable to natural field decline plus a higher royalty rate. Syncrude production totaled 12,546 barrels per day in 2008 compared to 12,948 barrels per day in 2007, with the decline caused by more downtime for repairs and maintenance in the current year. Oil production declined in the U.S. from 12,989 barrels per day in 2007 to 10,668 barrels per day in 2008. The reduction was primarily at Gulf of Mexico fields where production was curtailed while awaiting repairs to downstream facilities owned by other companies that were damaged by third quarter hurricanes. Oil production in the U.K. was down from 5,281 barrels per day in 2007 to 4,869 barrels per day in 2008, with the reduction caused by declining production at the Company’s primary fields in the North Sea. The West Patricia field, offshore Sarawak Malaysia, had net production of 4,403 barrels per day in 2008 after production levels of 8,709 barrels per day in 2007. West Patricia experienced declining production and a smaller portion of production was allocated to the Company’s account under the production sharing contract. Oil production from discontinued operations in Ecuador totaled 7,412 barrels per day in 2008, compared to 8,946 barrels per day in 2007 due to a shut-down of the Block 16 development drilling program during 2008 following an arbitrary decision by the government to impose a 99% revenue sharing provision starting in late 2007 on all sales prices exceeding a benchmark price that averaged about $23.50 per barrel during the year.
Total production of crude oil, condensate and natural gas liquids (including discontinued operations in Ecuador) in 2007 increased by 3,705 barrels per day, or 4% compared to 2006, primarily due to start-up in August of the Kikeh field in Block K, offshore Sabah, Malaysia. This prolific field came on production only five years after discovery. Kikeh produced 11,658 barrels of oil per day for the full-year 2007. 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 WCSB. Terra Nova produced throughout 2007 after being off-line for
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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 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 down from 10,996 barrels per day in 2006 as the field experienced production decline during the year. 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 Company’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 experienced declining production along with an increased government take under the production sharing contract. Oil production from discontinued operations in Ecuador totaled 8,946 barrels per day, up 338 barrels per day due to a more significant development drilling campaign in Block 16 in 2007.
Worldwide sales of natural gas were 55.5 million cubic feet (MMCF) per day in 2008, 61.1 million in 2007 and 75.3 million in 2006. Natural gas sales volumes in the United States increased 1% in 2008 and averaged 45.8 MMCF per day. The increase of 0.7 MMCF per day in 2008 would have been significantly higher but for the reduced gas production associated with hurricane damage to downstream facilities late in the year. Natural gas sales volumes in Canada averaged 1.9 MMCF per day in 2008, 81% lower than 2007. In January 2008, the Company sold Berkana Energy, formerly its largest gas producing asset in Canada. Natural gas sales volumes in the U.K. were up 7% in 2008 and averaged 6.4 MMCF per day. The U.K. gas sales volumes were mostly attributable to more gas volumes sold at the Mungo and Monan fields in the North Sea. Natural gas production commenced from the Kikeh field offshore Sabah Malaysia in December 2008 and sales volumes averaged 1.4 MMCF per day for the year.
Natural gas sales volumes 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 associated gas volumes sold from two oil fields in the North Sea.
The Company’s average worldwide realized crude oil, condensate and gas liquids sales price from continuing operations was $89.16 per barrel in 2008 compared to $65.15 per barrel in 2007. This was an increase of 37% in 2008. Oil prices began to plummet in the second half of 2008 and continued to display weakness in early 2009 as West Texas Intermediate crude oil prices averaged about $42 per barrel in January 2009. In the U.S., the Company realized an average price of $95.74 per barrel in 2008, up 46% from 2007. The average sales price in 2008 for heavy oil produced in Canada was $59.05 per barrel, 80% higher than in 2007. Hibernia and Terra Nova sales prices averaged $97.09 and $96.23 per barrel, respectively, during 2008, which were increases of 36% and 40%. Synthetic oil production sold for $100.10 per barrel, up 35% from a year earlier. U.K. oil prices increased 32% to $90.16 per barrel in 2008. In Malaysia, oil produced at the Kikeh field sold for 2% less in 2008 than in 2007, with an average of $89.36 per barrel for the just completed year. Kikeh came on stream in August 2007 and all sales during that year occurred in the fourth quarter when prices were at the strongest point during 2007. At the West Patricia field offshore Sarawak the 2008 average sales price of $72.04 per barrel was 22% above the 2007 average price.
The Company’s average realized oil sales price from continuing operations was $65.15 per barrel in 2007, up 21% from the 2006 average of $53.93 per barrel. In the U.S., the Company realized an average price of $65.57 per barrel in 2007, up 14% from 2006. The 2007 average sales price for Canadian heavy oil production 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 in 2007, 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 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 Company’s natural gas sales prices rose in 2008 compared to 2007. The Company’s average realized North American natural gas sales prices increased by 33% in 2008 to $9.54 per thousand cubic feet (MCF). In the U.K., the average 2008 natural gas price rose 46% to $10.98 per MCF.
The Company’s average realized North American natural gas sales prices fell 5% in 2007 to $7.19 per MCF. In the U.K., the average 2007 natural gas price rose 3% to $7.54 per MCF.
7
Based on 2008 sales volumes and deducting taxes at marginal rates, each $1.00 per barrel and $0.10 per MCF fluctuation in prices would have affected 2008 earnings from exploration and production continuing operations by $26.6 million and $1.3 million, respectively. The effect of these price fluctuations on consolidated net income cannot be measured precisely because operating results of the Company’s refining and marketing segments could be affected differently.
Production expenses from continuing operations were $611.5 million in 2008, $425.9 million in 2007 and $353.5 million in 2006. These amounts are shown by major operating area on pages F-39 and F-40 of this Form 8-K report. Costs per equivalent barrel during the last three years are shown in the following table.
(Dollars per equivalent barrel) | 2008 | 2007 | 2006 | ||||
United States | $ | 10.01 | 10.75 | 7.10 | |||
Canada | |||||||
Excluding synthetic oil | 9.44 | 8.77 | 9.36 | ||||
Synthetic oil | 41.08 | 30.56 | 28.23 | ||||
United Kingdom | 13.21 | 10.34 | 6.19 | ||||
Malaysia | 10.31 | 12.60 | 7.46 | ||||
Worldwide – excluding synthetic oil | 10.24 | 10.23 | 7.80 | ||||
Production cost per equivalent barrel decreased in the U.S. in 2008 compared to 2007 due to lower costs incurred for workovers and repairs at fields in the Gulf of Mexico. U.S. per-barrel equivalent costs were higher in 2007 versus 2006 mostly due to higher workover and field repairs and lower production volumes. The per-unit costs for Canadian conventional oil and gas operations, excluding Syncrude, were higher in 2008 than 2007 mostly due to lower production levels. The cost for conventional oil in Canada was lower in 2007 than 2006 primarily due to higher production levels and lower repair costs at Terra Nova in 2007. Terra Nova was shut-in for major repairs for six months in 2006. Higher production costs per barrel for Canadian synthetic oil operations in 2008 were due to additional costs for fuel and repairs and lower production levels. The increased Syncrude cost in 2007 was primarily due to a higher net profit royalty rate and a higher foreign exchange rate. The average cost per barrel in the U.K. in 2008 versus 2007 was caused by lower overall production levels and higher repair 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 lower average cost per barrel in Malaysia in 2008 compared to 2007 was attributable to higher production at Kikeh where unit costs per equivalent barrel are lower than at West Patricia. 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 compared to 2006.
Exploration expenses from continuing operations for each of the last three years are shown in total in the following table, and amounts are reported by major operating area on pages F-39 and F-40 on this Form 8-K report. Certain of the expenses are included in the capital expenditures total for exploration and production activities.
(Millions of dollars) | 2008 | 2007 | 2006 | ||||
Dry holes | $ | 129.5 | 66.8 | 109.6 | |||
Geological and geophysical | 85.2 | 67.7 | 73.1 | ||||
Other | 17.7 | 35.1 | 12.5 | ||||
| 232.4 | 169.6 | 195.2 | |||||
Undeveloped lease amortization | 112.0 | 33.2 | 22.5 | ||||
Total exploration expenses | $ | 344.4 | 202.8 | 217.7 | |||
Dry hole expense was $62.7 million more in 2008 than in 2007 and was attributable to more exploration drilling capital expenditures in 2008. With mostly new E&P management in 2007, much of that year was spent reevaluating the Company’s worldwide exploration drilling prospects. The higher costs for dry holes in 2008 was mostly in the offshore waters of Malaysia and Western Australia. Dry holes expense was $42.8 million less in 2007 than 2006 primarily due to a lower level of exploration drilling activity in 2007. Geological and geophysical (G&G) expenses were $17.5 million higher in 2008 mostly due to a 3D seismic program at Block 37, offshore Suriname, and more seismic activities in the Tupper area in British Columbia. G&G expenses were $5.4 million less in 2007 than 2006 primarily due to lower spending in Malaysia for 3D seismic for Blocks SK 311 and H and lower geophysical analyses on PM Blocks 311/312. 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 the Congo. Other exploration expenses in 2008 were $17.4 million lower than 2007 mostly due to a $21.9 million settlement in 2007 for unfulfilled work commitments on two expiring Scotian Shelf leases, offshore eastern Canada. Other exploration expenses in 2007 were $22.6 million higher than in 2006 also due to the Scotian Shelf work commitment settlement. Undeveloped leasehold amortization expense rose $78.8 million in 2008 compared to 2007, after an increase of $10.7 million in 2007 compared to 2006, primarily due to amortization of undeveloped land acquisition costs at the Tupper property in northeast British Columbia, where the Company has aggressively added undeveloped acreage over the last two years.
8
A $2.6 million charge in the exploration and production business for asset impairment in 2007 related to write-down of an unused E&P administrative office to estimated fair value.
Expense of $1.9 million was incurred in 2006 in the Company’s exploration and production operations for uninsured costs to repair damages and to recognize associated higher insurance costs caused by Hurricanes Katrina and Rita in the Gulf of Mexico.
Depreciation, depletion and amortization expense from exploration and production continuing operations totaled $527.8 million in 2008, $337.6 million in 2007 and $269.7 million in 2006. The increase of $190.2 million in 2008 expense compared to 2007 was mostly caused by a much higher production level at the Kikeh field, offshore Sabah, Malaysia. The $67.9 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 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 $23.5 million in 2008, $16.1 million in 2007 and $10.8 million in 2006 for accretion on discounted abandonment liabilities. Because the abandonment liability is 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 increase in accretion costs in 2008 was associated with higher estimated abandonment costs at Syncrude and additional development wells drilled at the Kikeh field. 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 Kikeh development wells drilled in 2007.
The effective income tax rate for exploration and production continuing operations was 37.4% in 2008, 34.2% in 2007 and 35.8% in 2006. The effective tax rate was higher in 2008 than the previous two years as both 2007 and 2006 included net tax benefits from enacted changes in foreign tax rates. Canada lowered federal tax rates in both 2007 and 2006, and in 2006 the Canadian provinces of Alberta and Saskatchewan also reduced 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. The 2008 effective tax rate exceeded the U.S. statutory tax rate due to higher overall foreign tax rates and exploration activities in areas where current tax relief is not available. The effective tax rate in 2007 was slightly below the U.S. statutory tax rate of 35% primarily due to the enacted Canadian Federal tax rate reduction during the year. The 2007 effective tax rate was lower than in 2006 mostly due to a deferred tax expense in 2006 related to a 10% increase in U.K. tax rates on oil and gas profits. A $4.4 million U.S. tax benefit was realized in 2007 for a charitable building donation. Also in 2007, the Company incurred lower exploration and other expenses in tax jurisdictions where tax relief is currently not available. Tax jurisdictions with no current tax benefit on expenses primarily include non-revenue generating areas in Malaysia, the Republic of the Congo, Suriname, Australia and Indonesia. Each main exploration area in Malaysia is currently considered a distinct taxable entity and expenses in certain areas may not be used to offset revenues generated in other areas. 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. The 2006 effective tax rate was only slightly higher than the U.S. statutory tax rate of 35% due to net overall benefits from the aforementioned tax rate changes in Canada and the U.K. in that year.
At December 31, 2008, approximately 38% of the Company’s U.S. proved oil reserves and 40% 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 Company’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, 23% of oil reserves of 76.6 million barrels and 25% of natural gas reserves of 106.5 billion cubic feet at year-end 2008 for the Kikeh field are undeveloped pending completion of facilities and continued development drilling, and 100% of the 15.1 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 298.7 billion cubic feet of undeveloped natural gas reserves at various fields offshore Sarawak at year-end 2008, which were held under this category pending completion of development drilling and facilities. First gas production at the Kikeh field occurred in December 2008 and is scheduled for the Sarawak gas fields in the third quarter 2009. On a worldwide basis, the Company spent approximately $783 million in 2008, $769 million in 2007 and $560 million in 2006 to develop proved reserves. The Company expects to spend about $859 million in 2009, $377 million in 2010 and $250 million in 2011 to move currently undeveloped proved reserves to the developed category.
9
Exploration and Production Statistical Summary
| 2008 | 2007 | 2006 | |||||
Net crude oil, condensate and natural gas liquids production – barrels per day | |||||||
United States | 10,668 | 12,989 | 21,112 | ||||
Canada – light | 46 | 596 | 443 | ||||
heavy | 8,484 | 11,524 | 12,613 | ||||
offshore | 16,826 | 18,871 | 14,896 | ||||
synthetic | 12,546 | 12,948 | 11,701 | ||||
United Kingdom | 4,869 | 5,281 | 7,146 | ||||
Malaysia | 57,403 | 20,367 | 11,298 | ||||
Continuing operations | 110,842 | 82,576 | 79,209 | ||||
Discontinued operations | 7,412 | 8,946 | 8,608 | ||||
Total liquids produced | 118,254 | 91,522 | 87,817 | ||||
Net crude oil, condensate and natural gas liquids sold – barrels per day | |||||||
United States | 10,668 | 12,989 | 21,112 | ||||
Canada – light | 46 | 596 | 443 | ||||
heavy | 8,484 | 11,524 | 12,613 | ||||
offshore | 16,690 | 18,839 | 15,360 | ||||
synthetic | 12,546 | 12,948 | 11,701 | ||||
United Kingdom | 5,739 | 5,218 | 6,678 | ||||
Malaysia | 61,907 | 16,018 | 11,986 | ||||
Continuing operations | 116,080 | 78,132 | 79,893 | ||||
Discontinued operations | 7,774 | 9,470 | 10,349 | ||||
Total liquids sold | 123,854 | 87,602 | 90,242 | ||||
Net natural gas sold – thousands of cubic feet per day | |||||||
United States | 45,785 | 45,139 | 56,810 | ||||
Canada | 1,910 | 9,922 | 9,752 | ||||
United Kingdom | 6,424 | 6,021 | 8,700 | ||||
Malaysia | 1,399 | — | — | ||||
Total natural gas sold – continuing operations | 55,518 | 61,082 | 75,262 | ||||
Net hydrocarbons produced – equivalent barrels1,2per day | 127,507 | 101,702 | 100,361 | ||||
Estimated net hydrocarbon reserves – million equivalent barrels1,2,3 | 402.8 | 405.1 | 388.3 | ||||
Weighted average sales prices4 | |||||||
Crude oil, condensate and natural gas liquids – dollars per barrel | |||||||
United States | $ | 95.74 | 65.57 | 57.30 | |||
Canada5– light | 70.37 | 50.98 | 50.45 | ||||
heavy | 59.05 | 32.84 | 25.87 | ||||
offshore | 96.69 | 69.83 | 62.55 | ||||
synthetic | 100.10 | 74.35 | 63.23 | ||||
United Kingdom | 90.16 | 68.38 | 64.30 | ||||
Malaysia6 | 87.83 | 74.58 | 51.78 | ||||
Natural gas – dollars per thousand cubic feet | |||||||
United States | 9.67 | 7.38 | 7.76 | ||||
Canada5 | 6.40 | 6.34 | 6.49 | ||||
United Kingdom5 | 10.98 | 7.54 | 7.34 | ||||
Malaysia | 0.23 | — | — | ||||
| 1 | Natural gas converted at a 6:1 ratio. |
| 2 | Includes synthetic oil. |
| 3 | At December 31. |
| 4 | Includes intercompany transfers at market prices. |
| 5 | U.S. dollar equivalent. |
| 6 | Prices are net of payments under the terms of the production sharing contracts for Blocks K and SK 309. |
10
Refining and Marketing – The Company’s refining and marketing (R&M) operations generated record earnings of $313.8 million in 2008, after earning $205.7 million in 2007 and $110.6 million in 2006. The 53% improvement in 2008 earnings compared to 2007 was caused by favorable U.K. refining profits following the acquisition of the remaining 70% of the Milford Haven refinery in December 2007, and nonrecurring charges in 2007 for a last-in, first-out (LIFO) inventory writedown in the U.K. and retail gasoline station impairments in North America.
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 and $67.1 million in 2006. The Meraux, Louisiana refinery significantly increased crude oil throughputs in 2007 compared to 2006 as the earlier year was unfavorably affected by downtime for repairs. R&M earnings in 2007 were net of two significant charges – 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 Company’s North American R&M operations generated earnings of $227.9 million in 2008, $230.4 million in 2007 and $77.5 million in 2006. North American operations include refining activities in the United States and marketing activities in the United States and Canada. North American R&M earnings were down slightly in 2008 compared to 2007 as lower profits generated by the U.S. refining operations were not quite offset by much stronger retail marketing profits in 2008. Demand for gasoline declined in the U.S. in 2008 due to higher costs and a weakening economy. This lower demand led to much tighter crack spreads for U.S. refineries in 2008 compared to 2007. Crack spreads represent the uplift of gasoline and distillate prices over the cost of crude oil feedstocks. Both U.S. refineries were temporarily shut-down for turnaround activities during 2008. The 2007 and 2006 operating results for the Company’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 Company’s North American operations were $3.0 million in 2007 and $107.3 million in 2006. The hurricane expense in 2007 was caused by a downward adjustment of expected insurance recoveries based on an updated loss limit published by the Company’s primary insurer. The Meraux refinery throughput volumes of crude oil and other feedstocks averaged 103,169 barrels per day in 2008, 112,840 barrels per day in 2007 and 57,198 barrels per day in 2006. 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 refinery’s nine months of downtime for repairs, major upgrades and improvements were completed, and turnarounds on the refinery’s hydrocracker and fluid catalytic cracking unit debutanizer were performed. The Company’s refinery in Superior, Wisconsin also generated weaker earnings in 2008 than in 2007 as a result of tighter crack spreads in the later year. North American retail gasoline station operations had improved results in 2008 compared to 2007 as this business enjoyed higher per gallon margins, higher sales volumes and lower store closure costs compared to the prior year. This operation’s business model of always offering competitive fuel prices usually leads to increased sales volumes during periods of high gasoline prices such as in the first nine months of 2008. The operating results for the Company’s North American retail gasoline stations were lower in 2007 compared to 2006 as 55 underperforming stores were closed during 2007, including 47 in the U.S. and all eight stations in Canada. The Company recorded impairment expense 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 52 retail stations were added in the U.S. during 2008, including 21 in the parking lots of Walmart Supercenters and 31 at other stand-alone locations. Average fuel sales volumes per station increased again in 2008, the 11th straight year of improvements.
Unit margins (sales realization less costs of crude and other feedstocks, transportation to point of sale and refinery operating and depreciation expenses) averaged $4.30 per barrel in North America in 2008, $4.28 in 2007 and $3.48 in 2006. North American refined product sales volumes increased 3% to a record 427,490 barrels per day in 2008, following a 19% increase to 416,668 barrels per day in 2007. The Company’s U.S. retail gasoline stations continued to increase per site fuel sales volumes with a 10% increase in the average monthly fuel sales volume per station in 2008 following a 4% increase in 2007.
Operations in the United Kingdom had earnings of $85.9 million in 2008 compared to a loss of $24.7 million in 2007 and earnings of $33.1 million in 2006. On December 1, 2007, the Company acquired 100% of the Milford Haven, Wales refinery, after having a 30% interest in the asset prior to that date. The improved earnings in 2008 compared to 2007 were mostly related to profits generated by the Milford Haven refinery as the refinery generated stronger margins in 2008 and the 2007 period included a significant inventory charge. In association with the late 2007 Milford Haven acquisition, the Company built a significant additional layer of crude oil and refined products inventory. The 2007 period 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 Company’s LIFO inventory accounting policy, inventory volume increases are priced at the first purchase prices during the year, and the prices of crude oil 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. The LIFO inventory charge reduced the average carrying
11
value for these additional inventories in the U.K. by approximately $40 per barrel. Excluding this non-cash inventory charge, the 2007 operating result for the Company’s U.K. operations was slightly improved over 2006. In late 2008, the Company purchased six existing fuel stations and leased an additional 63 stations in England and Scotland.
Unit margins in the United Kingdom averaged $4.30 per barrel in 2008, $0.22 per barrel in 2007 and $6.39 per barrel in 2006. Overall sales of refined products in the U.K. increased more than 200% in 2008, following an increase of 19% in 2007. The 2008 sales increase was attributable to additional quantities of refined products produced and sold throughout 2008 at the Milford Haven refinery following the Company’s acquisition of the remaining 70% interest in December 2007.
Refining and Marketing Statistical Summary
| 2008 | 2007 | 2006 | |||||
Refining | |||||||
Crude capacity* of refineries – barrels per stream day | 268,000 | 268,000 | 192,400 | ||||
Refinery inputs – barrels per day | |||||||
Crude – Meraux, Louisiana | 95,126 | 106,446 | 55,129 | ||||
Superior, Wisconsin | 26,580 | 32,737 | 34,066 | ||||
Milford Haven, Wales | 97,521 | 36,000 | 30,036 | ||||
Other feedstocks | 23,300 | 10,805 | 6,423 | ||||
Total inputs | 242,527 | 185,988 | 125,654 | ||||
Refinery yields – barrels per day | |||||||
Gasoline | 86,310 | 74,395 | 48,314 | ||||
Kerosene | 23,824 | 5,371 | 5,067 | ||||
Diesel and home heating oils | 75,526 | 67,111 | 42,137 | ||||
Residuals | 27,170 | 18,910 | 15,244 | ||||
Asphalt, LPG and other | 24,815 | 17,546 | 12,855 | ||||
Fuel and loss | 4,882 | 2,655 | 2,037 | ||||
Total yields | 242,527 | 185,988 | 125,654 | ||||
Average cost of crude inputs to refineries – dollars per barrel | |||||||
North America | $ | 96.46 | 69.40 | 59.54 | |||
United Kingdom | 100.61 | 81.53 | 66.66 | ||||
Marketing | |||||||
Products sold – barrels per day | |||||||
North America – Gasoline | 313,827 | 298,833 | 266,353 | ||||
Kerosene | 4,606 | 1,685 | 2,269 | ||||
Diesel and home heating oils | 86,933 | 91,344 | 62,196 | ||||
Residuals | 14,837 | 15,422 | 11,696 | ||||
Asphalt, LPG and other | 7,287 | 9,384 | 8,087 | ||||
| 427,490 | 416,668 | 350,601 | |||||
United Kingdom – Gasoline | 34,125 | 14,356 | 12,425 | ||||
Kerosene | 14,835 | 4,020 | 3,619 | ||||
Diesel and home heating oils | 34,560 | 14,785 | 11,803 | ||||
Residuals | 12,744 | 3,728 | 3,825 | ||||
LPG and other | 15,246 | 4,213 | 2,998 | ||||
| 111,510 | 41,102 | 34,670 | |||||
Total products sold | 539,000 | 457,770 | 385,271 | ||||
Branded retail outlets* | |||||||
North America – Murphy USA® | 992 | 971 | 987 | ||||
Murphy Express® | 33 | 2 | — | ||||
Other | 129 | 153 | 177 | ||||
Total | 1,154 | 1,126 | 1,164 | ||||
United Kingdom | 454 | 389 | 402 | ||||
| * | At December 31. |
12
Corporate– 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 $171.8 million in 2008, $95.2 million in 2007 and $85.9 million in 2006. The net cost of corporate activities increased $76.6 million in 2008 compared to 2007 primarily due to higher costs associated with foreign exchange where transactions are denominated in currencies other than the operation’s functional currency. Additionally interest costs, net of amounts capitalized to development projects, and administrative costs were also higher in 2008 than in 2007. The after-tax costs of foreign currency exchange amounted to $87.8 million in 2008 compared to costs of $13.8 million in 2007. The additional costs were primarily related to U.S. dollar transactions within the U.K.’s sterling functional downstream operations, as these dollar transactions expanded significantly with the 70% addition of Milford Haven, Wales refinery ownership beginning in December 2007. At year-end 2008 the U.S. dollar had strengthened 28% against the British pound sterling, 5% against the Euro, and 18% against the Canadian dollar compared to the end of 2007. Net interest expense increased $17.4 million in 2008 compared to 2007 mostly due to lower amounts of interest capitalized to ongoing oil and gas development projects during the just completed year. Administrative expenses in the corporate area increased in 2008 primarily due to higher total compensation expense and higher contributions to community and educational programs in the current year. Interest income increased $6.6 million in 2008 versus 2007 and was mostly associated with higher average short-term invested funds in Canada and the U.K. Income taxes in 2008 were favorable to 2007, and were primarily related to benefits on the higher foreign exchange losses and higher net interest expense as discussed above.
Net corporate costs increased $9.3 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 $15.3 million in 2007 compared to 2006 due to interest associated with higher average outstanding long-term debt balances. The Company’s borrowings increased due to higher capital spending on oil and natural gas development projects in Malaysia, the Republic of the 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 Walmart 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 a charge of $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 significantly 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 Company’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.
Capital Expenditures
As shown in the selected financial in Item 6 of this Form 8-K report, capital expenditures, including exploration expenditures, were $2,364.7 million in 2008 compared to $2,357.3 million in 2007 and $1,262.5 million in 2006. These amounts included capital expenditures related to discontinued operations in Ecuador. These amounts included $232.4 million, $169.6 million and $195.2 million, respectively, in 2008, 2007 and 2006 for exploration costs that were expensed. Capital expenditures for exploration and production continuing operations totaled $1,928.3 million in 2008, $1,740.3 million in 2007 and $1,046.5 million in 2006, representing 82%, 75% and 85%, respectively, of the Company’s total capital expenditures from continuing operations for these years. E&P capital expenditures in 2008 included $156.0 million for acquisition of undeveloped leases, which included leases acquired in the eastern and central Gulf of Mexico and at the Tupper area of northeastern British Columbia, $323.6 million for exploration activities, and $1,448.7 million for development projects. Development expenditures included $358.3 million for the Tupper natural gas area in British Columbia, $160.2 million for deepwater fields in the Gulf of Mexico; $325.7 million for the Kikeh field in Malaysia; $287.8 million for natural gas and other development activities in SK Blocks 309/311; $46.5 million for development of the Kakap field in Block K, offshore Malaysia; $35.6 million for synthetic oil operations at the Syncrude project in Canada; $37.6 million for western Canada heavy oil projects; $149.2 million for development of the Azurite field in the Republic of the Congo; $18.0 million for the Terra Nova and Hibernia oil fields, offshore Newfoundland; and $22.1 million for fields in the U.K. North Sea. Exploration and production capital expenditures are shown by major operating area on page F-38 of this Form 8-K report.
Refining and marketing capital expenditures totaled $426.2 million in 2008, $572.5 million in 2007 and $173.4 million in 2006. These amounts represented 18%, 25% and 14% of capital expenditures from continuing operations of the Company in 2008, 2007 and 2006, respectively. Refining capital spending was $141.8 million in 2008 compared to $330.0 million in 2007 and $57.3 million in 2006. Refining capital in 2008 included project costs for additional sulfur recovery capacity and property acquisition and improvements at the Meraux, Louisiana refinery, and a cogeneration energy plant at the Milford Haven, Wales refinery. The 2007 refining capital included $240.7 million for acquisition of the remaining 70%
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of the Milford Haven, Wales refinery. Most of the remaining refinery capital in 2007 was related to property acquired surrounding the Meraux refinery. The bulk of the refining capital in 2006 was spent at the Meraux refinery where numerous capital improvements were completed while the plant was shut-down for repairs following Hurricane Katrina. Marketing expenditures amounted to $284.4 million in 2008, $242.5 million in 2007 and $116.1 million in 2006. Marketing capital spending in 2008 was split between station construction costs and land acquisitions costs for existing and future retail gasoline stations. The capital spending in 2007 was mostly attributable to acquisition of land underlying retail gasoline stations located at Walmart Supercenters. The majority of marketing expenditures in 2006 was related to construction of retail gasoline stations at Walmart Supercenters in the U.S. The Company added 52 stations within its U.S. retail gasoline network in 2008, after adding 33 in 2007 and 123 in 2006.
Cash Flows
Cash provided by operating activities was $3.04 billion in 2008, $1.74 billion in 2007 and $975.5 million in 2006. Cash provided by operating activities in 2008 was $1.30 billion more than in 2007 primarily due to higher net income, higher depreciation and higher exploration drilling expenditures. 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 expenses for depreciation, impairment and deferred taxes, and a reduction of noncash operating working capital in 2007 versus an increase in 2006. Cash provided by operating activities in 2006 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 was reduced by expenditures for abandonment of oil and gas properties totaling $9.2 million in 2008, $13.0 million in 2007 and $3.3 million in 2006.
Cash proceeds from property sales were $362.0 million in 2008, $21.6 million in 2007 and $23.8 million in 2006. The 2008 proceeds related to sales of two of the Company’s Canadian assets, including its interest in Berkana Energy and the Lloydminster heavy oil property, and a sale of 35% of its working interest in the MPS block offshore the Republic of the Congo. The sales proceeds in 2007 and 2006 primarily related to sales of various properties, real estate and aircraft. During 2008, the Company used available cash flow to repay $492.8 million of long-term debt. 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 Company’s development capital expenditures. Cash proceeds from stock option exercises and employee stock purchase plans, including income tax benefits on stock options classified as financing activities, amounted to $50.0 million in 2008, $72.4 million in 2007 and $36.6 million in 2006. Proceeds from maturities of Canadian government securities with maturities greater than 90 days at date of acquisition was $623.1 million in 2008.
Property additions and dry hole costs used cash of $2.18 billion in 2008, $1.91 billion in 2007 and $1.16 billion in 2006. The higher capital expenditures in 2008 compared to 2007 were primarily associated with a more robust exploration program and higher spending on development projects including Kikeh development drilling, Sarawak natural gas, Kakap, Azurite, Tupper and Thunder Hawk. Higher amounts spent in 2007 compared to 2006 mostly related to ongoing E&P development projects, including Kikeh, Azurite, Sarawak gas and one field in the Gulf of Mexico, acquisition of mineral rights in the Tupper area of western Canada, and purchases of land under Company-owned gasoline stations at Walmart stores and surrounding the Meraux refinery. In December 2007, the Company spent $348.3 million to acquire the remaining 70% interest in the Milford Haven, Wales refinery and associated inventory. Cash of $1.04 billion was spent in 2008 to acquire Canadian government securities with maturities greater than 90 days at the time of purchase. Cash of $57.6 million in 2008, $14.6 million in 2007 and $12.8 million in 2006 was used for turnarounds at refineries and Syncrude. Cash used for dividends to stockholders was $166.5 million in 2008, $127.4 million in 2007 and $98.2 million in 2006. The Company raised its annualized dividend rate from $0.75 per share to $1.00 per share beginning in the third quarter of 2008. The Company had previously increased the annualized dividend rate from $0.60 per share to $0.75 per share beginning in the third quarter of 2007.
Financial Condition
Year-end working capital (total current assets less total current liabilities) totaled $958.8 million in 2008 and $777.5 million in 2007. The current level of working capital does not fully reflect the Company’s liquidity position as the carrying value for inventories under last-in, first-out accounting was $202.5 million below fair value at December 31, 2008. Cash and cash equivalents at the end of 2008 totaled $666.1 million compared to $673.7 million at year-end 2007.
The long-term portion of debt decreased by $489.9 million during 2008 and totaled $1.03 billion at year-end 2008, representing 14.0% of total capital employed. Available free cash flow arising primarily from strong crude oil sales prices was used to repay a portion of long-term debt during 2008. Long-term debt increased by $675.9 million in 2007 as the Company utilized its borrowing capacity to fund its significant ongoing oil and natural gas development projects, with the largest of these being the Kikeh field in Malaysia. Stockholders’ equity was $6.28 billion at the end of 2008 compared to $5.07 billion a year ago and $4.12 billion at the end of 2006. A summary of transactions in stockholders’ equity accounts is presented on page F-5 of this Form 8-K report.
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Other significant changes in Murphy’s year-end 2008 balance sheet compared to 2007 included a $420.3 million balance of short-term investments in Canadian government securities with maturities greater than 90 days at the time of purchase. There were no such investments with maturities greater than 90 days at December 31, 2007. These slightly longer-term investments were purchased in 2008 because of a tight supply of shorter-term securities available for purchase in Canada. A $386.6 million decrease in accounts receivable was caused by sales of crude oil and refined petroleum products at lower average prices near the end of 2008 compared to 2007. Inventory values were $22.5 million lower at year-end 2008 than in 2007 mostly due to less unsold crude oil production held in inventory at year-end 2008 compared to 2007. Prepaid expenses increased $13.0 million in 2008 primarily due to higher prepaid income taxes in the U.K. Short-term deferred income tax assets decreased $56.5 million at year-end 2008 due mostly to changes in the components of temporary differences for the Company’s Canadian operations. Net property, plant and equipment increased by $617.9 million in 2008 as a significant level of property additions during the year exceeded the additional depreciation and amortization expensed. Goodwill decreased $14.1 million in 2008 due to a weaker Canadian dollar exchange rate versus the U.S. dollar and an allocation of a portion of goodwill to costs associated with the sale of properties in Canada. Deferred charges and other assets increased $49.3 million and included higher amounts of deferred turnaround costs following major maintenance performed during the year at the Company’s U.S. refineries. Current maturities of long-term debt declined $2.6 million during 2008 due to a partial repayment of nonrecourse debt associated with the Hibernia field. Notes payable decreased $7.6 million in 2008 as this borrowing at year-end 2007 was associated with Berkana Energy Corp., which Murphy sold in January 2008. Accounts payable declined by $487.8 million at year-end 2008 compared to 2007 mostly due to lower amounts owed for crude oil purchases. Income taxes payable increased $342.6 million at year-end 2008 primarily due to higher taxes owed in the current year on income in Malaysia. Other taxes payable decreased $47.8 million mostly due to lower excise and value added taxes owed by the Company’s U.K. operations at year-end 2008 compared to 2007. Other accrued liabilities decreased by $18.0 million in 2008 mostly due to lower employee compensation liabilities in the current year. Deferred income tax liabilities were $38.8 million lower at year-end 2008 due mostly to lower liabilities for future taxes in the U.K. and Canada. The liability associated with future asset retirement obligations increased by $99.5 million mostly due to development wells drilled during 2008 offshore Malaysia and higher estimated future costs for abandonment of existing facilities at the Company’s synthetic oil operations in Canada. Deferred credits and other liabilities increased $50.8 million in 2008 compared to 2007 mostly due to higher long-term liabilities associated with employee retirement plans.
Murphy had commitments for future capital projects of approximately $2.13 billion at December 31, 2008, including $172.9 million for costs to develop deepwater Gulf of Mexico fields, $1.02 billion for field development and future work commitments in Malaysia, and $322.5 million for field development and a work commitment in the Republic of the Congo.
The primary sources of the Company’s liquidity are internally generated funds, access to outside financing and working capital. The Company uses its internally generated funds to finance the major portion of its capital and other expenditures, but it also maintains lines of credit with banks and borrows as necessary to meet spending requirements. At December 31, 2008, the Company had access to a long-term committed credit facility in the amount of $1.962 billion. A total of $318.5 million was borrowed under the committed credit facility at year-end 2008. The most restrictive covenants under this committed credit facility limit the Company’s long-term debt to capital ratio (as defined in the agreements) to 60%. At December 31, 2008, the long-term debt to capital ratio was approximately 14.0%. At December 31, 2008, the Company had borrowed $110 million under uncommitted credit lines. The Company’s shelf registration on file with the U.S. Securities and Exchange Commission that permitted the offer and sale of up to $650 million in debt and/or equity securities expired on December 31, 2008. The Company expects to file a new shelf registration in the second quarter of 2009. Current financing arrangements are set forth more fully in Note F to the consolidated financial statements. The Company anticipates matching its spending plans to cash inflows during 2009 in order to borrow little or no funds under its available credit facilities during the year. However, under a continued low price environment for oil and natural gas, the Company may have to borrow under these credit facilities to fund ongoing development projects. At February 27, 2009, the Company’s long-term debt rating by Standard & Poor’s was “BBB” and by Moody’s Investors Service was “Baa3”. The Company has a rating of A (low) from Dominion Bond Rating Service. The Company’s ratio of earnings to fixed charges was 28.3 to 1 in 2008, 14.0 to 1 in 2007 and 15.1 to 1 in 2006.
Environmental Matters
Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment. Compliance with existing and anticipated environmental regulations affects our overall cost of business. Areas affected include capital costs to construct, maintain and upgrade equipment and facilities, in concert with ongoing operating costs for environmental compliance. Anticipated and existing regulations affect our capital expenditures and earnings, and they may affect our competitive position to the extent that regulatory requirements
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with respect to a particular production technology may give rise to costs that our competitors might not bear. Environmental regulations have historically been subject to frequent change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of such regulations on our operations. Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject us to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result.
The most significant of those laws and the corresponding regulations affecting our U.S. operations are:
| • | The U.S. Clean Air Act, which regulates air emissions |
| • | The U.S. Clean Water Act, which regulates discharges into U.S. waters |
| • | The U.S. Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which addresses liability for hazardous substance releases |
| • | The U.S. Federal Resource Conservation and Recovery Act (RCRA), which regulates the handling and disposal of solid wastes |
| • | The U.S. Federal Oil Pollution Act of 1990 (OPA90), which addresses liability for discharges of oil into navigable waters of the United States |
| • | The U.S Safe Drinking Water Act, which regulates disposal of wastewater into underground wells |
| • | Regulations of the U.S. Department of the Interior governing offshore oil and gas operations. |
These laws and their associated regulations establish limits on emissions and standards for quality of air, water and solid waste discharges. They also generally require permits for new or modified operations. Many states and foreign countries where the Company operates also have or are developing similar statutes and regulations governing air and water as well as the characteristics and composition of refined products, which in some cases impose or could impose additional and more stringent requirements. We are also subject to certain acts and regulations, including legal and administrative proceedings, governing remediation of wastes or oil spills from current and past operations, which include but may not be limited to leaks from pipelines, underground storage tanks and general environmental operations.
CERCLA commonly referred to as the Superfund Act, and comparable state statutes primarily address historic contamination and impose joint and several liability upon Potentially Responsible Parties (PRP), without regard to fault or the legality of the original act that contributed to the release of a “hazardous substance” into the environment. Cleanup of contaminated sites is the responsibility of the owners and operators of the sites that released, disposed, or arranged for the disposal of the hazardous substances found at the site. CERCLA also authorizes the U.S. Environmental Protection Agency (EPA) and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible persons. In the course of our ordinary operations, we generate waste that falls within CERCLA’s definition of a “hazardous substance.” We may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which such hazardous substances have been disposed of or released into the environment. CERCLA also requires reporting of releases to the environment of substances defined as hazardous or extremely hazardous and must be reported to the National Response Center, if they exceed an EPA established reportable quantity.
The EPA currently considers us to be a PRP at two Superfund sites. The potential total cost to all parties to perform necessary remedial work at these sites may be substantial. However, based on current negotiations and available information, we believe that we are a de minimis party as to ultimate responsibility at these Superfund sites. We have not recorded a liability for remedial costs on Superfund sites. We could be required to bear a pro rata share of costs attributable to nonparticipating PRPs or could be assigned additional responsibility for remediation at these sites or other Superfund sites. We believe that our share of the ultimate costs to clean-up the Superfund sites will be immaterial and will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.
We currently own or lease, and have in the past owned or leased, properties at which hazardous substances have been or are being handled. Although we have used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. While some of these historical properties are in various stages of negotiation, investigation, and/or cleanup, we are investigating the extent of any such liability and the availability of applicable defenses and believe costs related to these sites will not have a material adverse affect on Murphy’s net income, financial condition or liquidity in a future period.
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RCRA and comparable state statutes govern the management and disposal of solid wastes, with the most stringent regulations applicable to treatment, storage or disposal of hazardous wastes. We generate non-hazardous solid wastes that are subject to the requirements of RCRA and comparable state statutes. Our operating sites also incur costs to handle and dispose of hazardous waste and other chemical substances. The types of waste and substances disposed of generally fall into the following categories: spent catalysts (usually hydro-treating catalysts); spent/used filter media; tank bottoms and API separator sludge; contaminated soils; laboratory and maintenance spent solvents; and industrial debris. The costs of disposing of these substances are expensed as incurred and are not expected to have a material adverse effect on net income, financial condition or liquidity in a future period. However, it is possible that additional wastes, which could include wastes currently generated during operations, will in the future be designated as “hazardous wastes.” Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. Such changes in the regulations could result in additional capital expenditures and operating expenses.
Murphy allocates a portion of its capital expenditure program to comply with environmental laws and regulations, and such capital expenditures were $121.7 million in 2008 and are projected to be $132.6 million in 2009.
Our liability for remedial obligations includes certain amounts that are based on anticipated regulatory approval for proposed remediation of former refinery waste sites. Although regulatory authorities may require more costly alternatives than the proposed processes, the cost of such potential alternative processes is not expected to exceed the accrued liability by a material amount. Certain environmental expenditures are likely to be recovered by us from other sources, primarily environmental funds maintained by certain states. Since no assurance can be given that future recoveries from other sources will occur, we have not recorded a benefit for likely recoveries as of December 31, 2008.
We are also involved in personal injury and property damage claims, allegedly caused by exposure to or by the release or disposal of materials manufactured or used in our operations. Under our accounting policies, an environmental liability is recorded when such an obligation is probable and the cost can be reasonably estimated. If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used. Recorded liabilities are reviewed quarterly. Actual cash expenditures often occur one or more years after a liability is recognized.
Under OPA90, owners and operators of tankers, owners and operators of onshore facilities and pipelines, and lessees or permittees of an area in which an offshore facility is located are liable for removal and cleanup costs of oil discharges into navigable waters of the United States. To the best of our knowledge, there has been no such OPA90 claims made against Murphy.
The EPA has issued several standards applicable to the formulation of motor fuels, primarily related to the level of sulfur found in highway diesel and gasoline, which are designed to reduce emissions of certain air pollutants when the fuel is used. Several states have passed similar or more stringent regulations governing the formulation of motor fuels. The EPA’s mandated requirements for low-sulfur gasoline are effective in 2008 and both of our U.S. refineries have been expanded and are now capable of producing the required low-sulfur gasoline. Each of the U.S. refineries must begin to produce the EPA required ultra low-sulfur diesel (ULSD) beginning in 2010. The Meraux refinery is currently capable of producing this ULSD for approximately half of its diesel production, but the Superior refinery is not yet capable of meeting the ULSD standard. Our management is currently studying alternatives available for fully meeting this ULSD standard at Meraux and Superior.
The Energy Independence and Security Act (EISA) was signed into law in December 2007. The EIS Act through EPA regulation requires refiners and gasoline blenders to obtain renewable fuel volume or representative trading credits as a percentage of their finished product production. This Act greatly increases the renewable fuels obligation defined in the Renewable Fuels Standard which began in September 2007. Murphy is actively blending renewable fuel volumes through its retail and wholesale operations and trading corresponding credits known as Renewable Identification Numbers (RINs) to meet its obligation.
The Federal Water Pollution Control Act of 1972 (FWPCA) imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters. The FWPCA imposes substantial potential liability for the costs of removal, remediation and damages. We maintain wastewater discharge permits for our facilities where they are required pursuant to the FWPCA and comparable state laws. We have also applied for all necessary permits to discharge storm water under such laws. We believe that compliance with existing permits and foreseeable new permit requirements will not have a material adverse effect on our net income, financial condition or liquidity in a future period.
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Our U.S. operations are subject to the Federal Clean Air Act and comparable state and local statutes. We believe that our operations are in substantial compliance with these statutes in all states in which we operate. Amendments to the Federal Clean Air Act enacted in late 1990 require or will require most refining operations in the U.S. to incur capital expenditures in order to meet air emission control standards developed by the EPA and state environmental agencies.
Under the EPA’s Clean Air Act authority, the National Petroleum Refinery (NPR) Initiative (Global Consent Decree) was initiated as a national priority to investigate four marquee compliance areas for refinery operations: (i) New Source Review/Prevention of Significant Deterioration for fluidized catalytic cracking units, heaters and boilers; (ii) New Source Performance Standards for flares, sulfur recovery units, fuel gas combustion devices (including heaters and boilers); (iii) Leak Detection and Repair requirements; and (iv) Benzene National Emissions Standards for Hazardous Air Pollutants. Murphy, in 2005 began negotiations with the EPA, which were interrupted by the events of Hurricane Katrina. Both the state of Louisiana and Wisconsin are parties to the NPR. Negotiations with EPA resumed in 2007 and are continuing. While substantial progress has been made in these negotiations, the Company is unable at this time to predict the capital costs, operating costs and potential fines or penalties that may occur in the future upon conclusion of the NPR negotiations.
Our Meraux, Louisiana refinery is also currently negotiating with the Louisiana Department of Environmental Quality (LDEQ) regarding three Compliance Order/Notice of Proposed Penalty (CO/NOPP) notifications regarding air and water discharges. While we are in various stages of negotiations and/or settlement, the Company is unable to predict the costs that it will incur related to these CO/NOPP negotiations.
World leaders have held numerous discussions about the level of worldwide greenhouse gas emissions. As part of these discussions, the Kyoto Agreement was adopted in 1997 and was ratified by certain countries in which we operate or may operate in the future, with the United States being the primary country that has yet to ratify the agreement. The agreement became effective for ratifying countries in 2005 and these countries have implemented regulations or are in various stages of developing regulations to address its contents that ultimately target a reduction in greenhouse gas emissions. We are unable to predict how U.S. regulations (if any) associated with the Kyoto Agreement will impact costs in future years. The European Union has adopted an Emissions Trading Scheme in response to the Kyoto Agreement in order to achieve reductions in greenhouse gas emissions. Our refining operations at Milford Haven currently have the most exposure to these requirements and may require purchase of emission allowances to maintain compliance with environmental permit requirements. These environmental expenditures are expensed as incurred.
Currently, various national and international legislative and regulatory measures to address greenhouse gas emissions (including carbon dioxide, methane and nitrous oxides) are in various phases of discussion or implementation. These include proposed U.S. federal legislation and state actions to develop statewide or regional programs, each of which have imposed or would impose mandatory reporting and reductions in greenhouse gas emissions. These actions could result in increased costs to (i) operate and maintain our facilities; (ii) install new emission controls on our facilities; and (iii) administer and manage any greenhouse gas emissions program. These actions could also impact the consumption of refined products, thereby affecting our refinery operations. The Company is unable to predict at this time how much the cost of compliance with any future U.S. legislation or regulation of greenhouse gas emissions, if it occurs, will be in future periods. Proactively, Murphy has instituted an internal Climate Change workgroup, conducts annual greenhouse gas inventories and participates in the Massachusetts Institute of Technology (MIT) Joint Program on the Science and Policy of Global Change.
Safety Matters
We are also subject to the requirements of the Federal Occupational Safety and Health Act (OSHA) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, record-keeping requirements and monitoring of occupational exposure to regulated substances.
In 2007, OSHA announced a National Emphasis Program (NEP) for inspecting all refineries in the U.S. for compliance with OSHA’s Process Safety Management (PSM) regulations. OSHA completed an inspection of our Superior, Wisconsin refinery in February 2008 and issued several compliance related citations and a penalty of $179,000. As of December 31, 2008, all of the cited OSHA items have been abated.
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Other Matters
Impact of inflation– General inflation was moderate during the last three years in most countries where the Company operates; however, the Company’s revenues and capital and operating costs are influenced to a larger extent by specific price changes in the oil and gas and allied industries than by changes in general inflation. Crude oil and petroleum product prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC production levels and/or attitudes of traders concerning supply and demand in the near future. Natural gas prices are affected by supply and demand, which to a significant extent are affected by the weather and by the fact that delivery of gas is generally restricted to specific geographic areas. Prices for oil field goods and services have generally risen (with certain of these price increases such as drilling rig day rates having been significant) during the last few years primarily driven by high demand for such goods and services when oil and gas prices were strong. As noted earlier, oil and natural gas prices have fallen significantly in late 2008 and early 2009, however, the prices for oil goods and services have not generally declined in tandem with oil and gas prices. Should a lower price environment for oil and gas continue, the Company anticipates that prices for certain equipment and services will decline due to falling demand for such items. Due to the volatility of oil and natural gas prices, it is not possible to determine what effect these prices will have on the future cost of oil field goods and services.
Accounting changes and recent accounting pronouncements – In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, Fair Value Measurements (SFAS No. 157). This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This statement applies under other accounting pronouncements that require or permit fair value measurements, and where applicable simplifies and codifies related guidance within GAAP and does not require any new fair value measurements. The statement was originally effective for fiscal years beginning January 1, 2008. On February 12, 2008, the FASB issued FSP No. 157-2 that delayed for one year the effective date of SFAS No. 157 for most nonfinancial assets and nonfinancial liabilities. Provisions of the statement are to be applied prospectively except in limited situations. The Company adopted this statement as of January 1, 2008 and the adoption had no material impact on its consolidated financial statements. See further disclosures at Note O to the consolidated financial statements.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS No. 159). This pronouncement permits companies with eligible financial assets and financial liabilities to measure these items at fair value in the financial statements. This option to measure at fair value is both instrument specific and irrevocable. If the fair value option is elected, certain additional disclosures are required and financial statements for periods prior to the adoption may not be restated. This pronouncement was effective January 1, 2008 for the Company. The Company chose not to elect fair value measurement for any financial assets and financial liabilities, and therefore, the adoption of SFAS No. 159, had no impact on the Company’s consolidated balance sheet or consolidated statement of income.
In June 2007, the FASB ratified the Emerging Issues Task Force’s Issue No. 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards (EITF 06-11). This new guidance was effective for the Company beginning January 1, 2008 and required that income tax benefits received by the Company for dividends paid on share-based incentive awards be recorded in Capital in Excess of Par Value in Stockholders’ Equity. Under certain circumstances, such tax benefits received on awards that do not vest could be reclassified to reduce income tax expense in the Consolidated Statements of Income. The effect of adopting EITF No. 06-11 in 2008 was not material to the Company’s consolidated financial statements.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51. This statement is effective for the Company beginning January 1, 2009. Upon adoption, this statement will require noncontrolling interests to be reclassified as equity, and consolidated net income and comprehensive income shall include the respective results attributable to noncontrolling interests. It is to be applied prospectively and early adoption is not permitted. The Company does not expect this statement to have a significant effect on its consolidated financial statements.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations. This statement establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquired business. It also establishes how to recognize and measure goodwill acquired in the business combination or a gain from a bargain purchase, if applicable. This statement shall be applied prospectively by the Company to any business combination that occurs on or after January 1, 2009. Early application is prohibited. Assets and liabilities that arise from business combinations occurring prior to 2009 shall not be adjusted upon application of this statement. This statement will impact the recognition and measurement of assets and liabilities in business combinations that occur after 2008, and the Company is unable to predict at this time how the application of this statement will affect its financial statements in future periods.
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In March 2008, the FASB issued SFAS No. 161, Disclosure about Derivative Instruments and Hedging Activities. This statement is effective for the Company beginning in January 2009, and it expands required disclosures regarding derivative instruments to include qualitative information about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. The Company does not expect this statement to have a significant effect on its consolidated financial statements.
In June 2008, the FASB issued FASB Staff Position on EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities (FSP EITF 03-6-1). This statement provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings per share (EPS) calculation under the two-class method. All prior-period EPS calculations must be adjusted retrospectively. This statement is effective for the Company in 2009. Although the Company is in the process of evaluating this statement, it does not expect the effect of adopting this statement in 2009 to have a significant impact on its prior-period EPS calculations.
In December 2008, the FASB issued Staff Position No. FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets. This guidance will require additional disclosures about benefit plan assets, including how asset investment allocation decisions are made, the fair value of each major category of plan assets, and how fair value is determined for each major asset category. This guidance is effective for the Company at year-end 2009. Upon adoption, no comparative disclosures are required for earlier years presented. The Company does not expect the adoption of this standard to have a material impact on its consolidated financial statements in future periods.
In November 2008, the EITF published Issue No. 08-6, Equity Method Investment Accounting Considerations. This pronouncement gives guidance about how to initially measure contingent consideration for an equity method investment, how to recognize other-than-temporary impairments of an equity method investment, and how an equity method investor is to account for a share issuance by an investee. This guidance is effective for the Company at the beginning of its 2009 fiscal year. The guidance is to be applied prospectively and early adoption is not permitted. The Company is currently evaluating this guidance and is unable to predict at this time how it will impact its consolidated financial statements in future periods.
Significant accounting policies – In preparing the Company’s consolidated financial statements in accordance with U.S. generally accepted accounting principles, management must make a number of estimates and assumptions related to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Application of certain of the Company’s accounting policies requires significant estimates. The most significant of these accounting policies and estimates are described below.
| • | Proved oil and natural gas reserves – Proved reserves are defined by the U.S. Securities and Exchange Commission (SEC) as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Although the Company’s engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. SEC rules require that year-end oil and natural gas prices must be used for determining proved reserve quantities. Year-end prices usually do not approximate the average price that the Company expects to receive for its oil and natural gas production. The Company often uses significantly different oil and natural gas price and reserve assumptions when making its own internal economic property evaluations. Estimated reserves are subject to future revision, certain of which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and natural gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to adjustments of the Company’s depreciation rates and the timing of settlement of asset retirement obligations. |
The Company’s proved reserves of oil and natural gas are presented on page F-36 of this Form 8-K. An unfavorable U.S. oil revision in 2008 resulted from updated reservoir modeling of one field in the deepwater Gulf of Mexico. An unfavorable revision in Canada in 2008 was related to low heavy oil prices at year-end, but this was partially offset by a favorable impact from better field performance at Hibernia. A favorable oil reserve revision in Malaysia was attributable to better than anticipated drilling results and additional drilling opportunities in the main reservoir at the
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Kikeh field, coupled with better reservoir performance and artificial lift improvements at the West Patricia field. An unfavorable oil reserve revision in the U.S. in 2007 was mostly related to poor performance at one deepwater field in the Gulf of Mexico. Favorable oil reserve revisions in 2007 in Canada relate primarily to better performance at the Hibernia and Terra Nova fields. Favorable 2007 oil revisions in Malaysia relate to West Patricia and Kikeh well performances. The oil reserve revisions in 2006 in the U.S., Canada, Malaysia and Ecuador were based on performance of various local wells. The favorable oil reserve revision in Malaysia in 2006 was mostly due to extension of proved oil in the Kikeh reservoir. An unfavorable natural gas reserve revision in Malaysia in 2008 was related to entitlement adjustments under the Sarawak Blocks SK 309 and SK 311 production sharing contract and gas volumes lost due to operational delays that restricted sales volumes at the Kikeh field, offshore Sabah. Downward revisions to U.S. natural gas reserves in 2007 and 2006 were mostly caused by unfavorable production performance for gas wells at various fields in the Gulf of Mexico and onshore south Louisiana. The favorable natural gas reserve revision in Canada in 2007 is mostly attributable to well performance at the natural gas field owned by a consolidated subsidiary. The downward revision to 2007 natural gas reserves in Malaysia is based on higher contractual sales prices at year-end 2007 compared to 2006. The significant upward revision of natural gas reserves in Malaysia in 2006 related to gas associated with the Kikeh field that will be sold to the local government beginning in 2008. The Company cannot predict the type of reserve revisions that will be required in future periods.
On December 29, 2008, the SEC adopted revisions to oil and natural gas reserve reporting requirements which are effective for the Company at year-end 2009, unless the timing is subsequently amended. Among other things, the rule:
| • | revises the definition of proved reserves, including the pricing used to determine economic producibility, |
| • | expands the definition of oil and gas producing activities to include non-traditional and unconventional resources, which includes the Company’s synthetic oil operations in Alberta, and |
| • | allows, but does not require, companies to disclose probable and possible reserves in SEC filings. |
The Company is currently evaluating these new rules and cannot predict how the new rules will affect its future reporting of oil and natural gas reserves. The full rule is available at the SEC’s website at www.sec.gov.
| • | Successful efforts accounting – The Company utilizes the successful efforts method to account for exploration and development expenditures. Unsuccessful exploration wells are expensed and can have a significant effect on net income. Successful exploration drilling costs, all development capital expenditures and asset retirement costs are capitalized and systematically charged to expense using the units of production method based on proved developed oil and natural gas reserves as estimated by the Company’s engineers. |
In some cases, a determination of whether a drilled well has found proved reserves can not be made immediately. This is generally due to the need for a major capital expenditure to produce and/or evacuate the hydrocarbon(s) found. The determination of whether to make such a capital expenditure is, in turn, usually dependent on whether additional exploratory wells find a sufficient quantity of additional reserves. Under current accounting rules, the Company holds well costs in Property, Plant and Equipment in the Consolidated Balance Sheet when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
Based on the time required to complete further exploration and appraisal drilling in areas where hydrocarbons have been found but proved reserves have not been booked, dry hole expense may be recorded one or more years after the original drilling costs are incurred. Dry hole expense related to wells drilled in a prior year was $3.4 million in 2006; there were no dry holes in 2008 or 2007 that were drilled in prior years.
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| • | Impairment of long-lived assets – The Company continually monitors its long-lived assets recorded in Property, Plant and Equipment and Goodwill in the Consolidated Balance Sheet to make sure that they are fairly presented. The Company must evaluate its properties for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable from future cash flows. Goodwill is evaluated for impairment at least annually. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the amount of oil and natural gas that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, future capital and abandonment costs, future margins on refined products produced and sold, and future inflation levels. The need to test a property for impairment can be based on several factors, including but not limited to a significant reduction in sales prices for oil and/or natural gas, unfavorable reserve revisions, expected deterioration of future refining and/or marketing margins for refined products, or other changes to contracts, environmental regulations or tax laws. All of these same factors must be considered when evaluating a property’s carrying value for possible impairment. |
In making its impairment assessments involving exploration and production property and equipment, the Company must make a number of projections involving future oil and natural gas sales prices, future production volumes, and future capital and operating costs. Due to the volatility of world oil and gas markets, the actual sales prices for oil and natural gas have often been quite different from the Company’s projections. Estimates of future oil and gas production and sales volumes are based on a combination of proved and risked probable and possible reserves. Although the estimation of reserves and future production is uncertain, the Company believes that its estimates are reasonable; however, there have been cases where actual production volumes were higher or lower than projected and the timing was different than the original projection. The Company adjusts reserves and production estimates as new information becomes available. The Company generally projects future costs by using historical costs adjusted for both assumed long-term inflation rates and known or expected changes in future operations. Although the projected future costs are considered to be reasonable, at times, costs have been higher or lower than originally estimated. In assessing potential impairment involving refining and marketing assets, the Company evaluates its properties when circumstances indicate that carrying value of an asset may not be recoverable from future cash flows. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events, which include projections of future margins, future capital expenditures and future operating expenses. Future marketing or operating decisions, such as closing or selling certain assets, and future regulatory or tax changes could also impact the Company’s conclusion about potential asset impairment. Based on an evaluation of expected future cash flows from properties at year-end 2008, the Company does not believe it had any significant properties with carrying values that were impaired at that date. The expected future sales prices for crude oil and natural gas used in the evaluation were based on quoted future prices for the respective production periods. These quoted prices generally reflected higher expected prices for oil and natural gas in the future compared to the existing spot prices at the end of 2008. If quoted prices for future years had been lower, the smaller projected cash flows for properties could have led to significant impairment charges being recorded for certain properties in 2008. In addition, one or a combination of factors such as lower future sales prices, lower future production, higher future costs, lower future margins on refining and marketing sales, or the actions of government authorities could lead to impairment expenses in future periods. Based on these unknown future factors as described herein, the Company can not predict the amount or timing of impairment expenses that may be recorded in the future.
| • | Income taxes– The Company is subject to income and other similar taxes in all areas in which it operates. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of its annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; and (c) future events often impact the timing of when income tax expenses and benefits are recognized by the Company. The Company has deferred tax assets mostly relating to basis differences for property, equipment and inventories, and dismantlements and retirement benefit plan liabilities. The Company routinely evaluates all deferred tax assets to determine the likelihood of their realization. A valuation allowance has been recognized for deferred tax assets related to basis differences for Blocks H, PM 311/312, P, L and M in Malaysia, exploration licenses in the Republic of the Congo and Australia, and certain basis differences in the U.K. due to management’s belief that these assets cannot be deemed to be realizable with any degree of confidence at this time. The Company occasionally is challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions in its various income tax returns. Although the Company believes that it has adequate accruals for matters not resolved with various taxing authorities, gains or losses could occur in future years from changes in estimates or resolution of outstanding matters. |
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| • | Accounting for retirement and postretirement benefit plans – Murphy Oil and certain of its subsidiaries maintain defined benefit retirement plans covering most of its full-time employees. The Company also sponsors health care and life insurance benefit plans covering most retired U.S. employees. The expense associated with these plans is determined by management based on a number of assumptions and with consultation assistance from qualified third-party actuaries. The most important of these assumptions for the retirement plans involve the discount rate used to measure future plan obligations and the expected long-term rate of return on plan assets. For the retiree medical and insurance plans, the most important assumptions are the discount rate for future plan obligations and the health care cost trend rate. Discount rates are adjusted as necessary, generally based on the universe of high-quality corporate bonds available within each country, and after cash flow analyses are performed to discount projected benefit payment streams. Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics. Anticipated health care cost trend rates are determined based on prior experience of the Company and an assessment of near-term and long-term trends for medical and drug costs. |
Based on bond yields at year-end 2008, the Company has used a discount rate of 6.50% in 2008 and beyond for the primary U.S. plans. Although the Company presently assumes a return on plan assets of 6.50% for the primary U.S. plan, it periodically reconsiders the appropriateness of this and other key assumptions. The smoothing effect of current accounting regulations tends to buffer the current year’s pension expense from wide swings in liabilities and asset valuations. The Company’s normal annual retirement and postretirement plan expenses are expected to increase slightly in 2009 compared to 2008 based on the effects of a growing employee base. In 2008, the Company paid $50.6 million into various retirement plans and $4.0 million into postretirement plans. In 2009, the Company is expecting to fund payments of approximately $50.2 million into various retirement plans and $4.9 million for postretirement plans. The 2009 retirement plan contribution includes a currently anticipated voluntary contribution of $30.0 million. The Company could be required to make additional and more significant funding payments to retirement plans in future years. Future required payments and the amount of liabilities recorded on the balance sheet associated with the plans could be unfavorably affected if the discount rate declines, the actual return on plan assets falls below the assumed 6.5%, or the health care cost trend rate increase is higher than expected. As described above, the Company’s retirement and postretirement expenses are sensitive to certain assumptions, primarily related to discount rates and assumed return on plan assets. A 0.5% decline in the discount rate would increase 2009 annual retirement and postretirement expenses by $3.8 million and $0.6 million, respectively, and a 0.5% decline in the assumed rate of return on plan assets would increase 2009 retirement expense by $1.4 million.
| • | Legal, environmental and other contingent matters– A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and other contingent matters. In addition, the Company often must estimate the amount of such losses. In many cases, management’s judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. The Company’s management closely monitors known and potential legal, environmental and other contingent matters, and makes its best estimate of the amount of losses and when they should be recorded based on information available to the Company. |
Contractual obligations and guarantees – The Company is obligated to make future cash payments under borrowing arrangements, operating leases, purchase obligations primarily associated with existing capital expenditure commitments, and other long-term liabilities. In addition, the Company expects to extend certain operating leases beyond the minimum contractual period. Total payments due after 2008 under such contractual obligations and arrangements are shown below.
| Amount of Obligation | |||||||||||
(Millions of dollars) | Total | 2009 | 2010-2011 | 2012-2013 | After 2013 | ||||||
Total debt including current maturities | $ | 1,028.8 | 2.6 | — | 778.1 | 248.1 | |||||
Operating leases | 813.1 | 96.3 | 181.0 | 165.1 | 370.7 | ||||||
Purchase obligations | 3,186.3 | 2,124.6 | 795.6 | 161.9 | 104.2 | ||||||
Other long-term liabilities | 630.1 | 70.9 | 42.6 | 80.6 | 436.0 | ||||||
Total | $ | 5,658.3 | 2,294.4 | 1,019.2 | 1,185.7 | 1,159.0 | |||||
The Company has entered into an agreement to lease production facilities for the Kikeh field offshore Malaysia. In addition, the Company has other arrangements that call for future payments as described in the following section. The Company’s share of the contractual obligations under these leases and other arrangements has been included in the table above.
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In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide financial guarantees or letters of credit that may be drawn upon if the Company fails to perform under those contracts. The amount of commitments as of December 31, 2008 that expire in future periods is shown below.
| Amount of Commitment | |||||||||||
(Millions of dollars) | Total | 2009 | 2010-2011 | 2012-2013 | After 2013 | ||||||
Financial guarantees | $ | 7.8 | — | — | — | 7.8 | |||||
Letters of credit | 120.0 | 116.0 | .6 | — | 3.4 | ||||||
Total | $ | 127.8 | 116.0 | .6 | — | 11.2 | |||||
Material off-balance sheet arrangements– The Company occasionally utilizes off-balance sheet arrangements for operational or funding purposes. The most significant of these arrangements at year-end 2008 includes an operating lease of the Kikeh floating, production, storage and offloading vessel (FPSO), a natural gas transportation contract for the Tupper area in British Columbia and a hydrogen purchase contract for the Meraux refinery. The Kikeh FPSO lease calls for future monthly net lease payments over the next seven years. The Tupper transportation contract requires minimum monthly payments through 2013. The Meraux refinery contract to purchase hydrogen ends in 2021. The hydrogen contract requires a monthly minimum base facility charge whether or not any hydrogen is purchased. Future required minimum annual payments under these arrangements are included in the contractual obligation table shown above.
Outlook
Prices for the Company’s primary products are often quite volatile. A strong global economy, which fueled demand for energy, led to generally stronger prices for crude oil and refined petroleum products during 2007 and the first half of 2008. Beginning in the second half of 2008 and continuing into early 2009, crude oil prices have fallen precipitously from the highs at mid-year 2008. The decline in the prices for crude oil is primarily attributable to softening demand for energy associated with the worldwide economic downturn. Due to the weak prices for crude oil and North American natural gas prices, the Company is making substantial efforts to balance its cash flow and spending in early 2009.
The Company’s capital expenditure budget for 2009 was prepared during the fall of 2008 and based on this budget capital expenditures are expected to be below 2008 levels. Since the budget was approved by the Company’s Board of Directors, crude oil and North American natural gas prices have generally been below the levels assumed in the 2009 budget. Based on a recent review of capital expenditure projects, capital expenditures in 2009 are projected to total approximately $2 billion. Of this amount, $1.7 billion or about 87%, is allocated for the exploration and production program. Geographically, E&P capital is spread approximately as follows: 16% for the United States, 42% for Malaysia, 23% for Canada and 19% for all other areas. Spending in the U.S. is primarily associated with continued development of producing and nonproducing deepwater fields as well as for the Company’s Gulf of Mexico exploration program. In Malaysia, the majority of the spending is for continued development of natural gas fields in Blocks SK 309 and 311 offshore Sarawak where first production is anticipated in 2009 and the Kakap field in Block K. The bulk of Canadian spending in 2008 will relate to natural gas development at Tupper in Western Canada. Spending in the Republic of the Congo includes continuing development costs for the Azurite discovery offshore, which is scheduled to start production in mid-2009. Refining and marketing expenditures in 2009 should be about $250 million, including funds for construction of additional U.S. retail gasoline stations and early costs for an expansion of the crude unit at the Milford Haven, Wales refinery. Capital and other expenditures will be routinely reviewed during 2009 and planned capital expenditures may be adjusted to reflect differences between budgeted and actual cash flow during the year. Capital expenditures may also be affected by asset purchases, which often are not anticipated at the time the Budget is prepared.
The Company will primarily fund its capital program in 2009 using operating cash flow, but will supplement funding where necessary using borrowings under available credit facilities. The Company will endeavor to have no increase in long-term debt in 2009, but a continued low price environment could reduce actual cash flow generated from operations to such a level that borrowings might be required during the year to maintain funding of the Company’s ongoing development projects. As noted earlier, crude oil and North American natural gas prices in early 2009 were well below the levels assumed in the 2009 budget. Also, through early 2009, margins within the Company’s refining and marketing operations were generally below amounts included in the Company’s 2009 budget.
The Company currently expects production in 2009 to average about 180,000 barrels of oil equivalent per day. A key assumption in projecting the level of 2009 Company production is the anticipated ramp up of natural gas production from Tupper in western Canada and Kikeh offshore Sabah Malaysia, and start-up of natural gas production offshore Sarawak Malaysia. In addition, continued reliability of production at significant fields such as Kikeh, Syncrude, Hibernia and Terra Nova are necessary to achieve the anticipated 2009 production levels.
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Forward-Looking Statements
This Form 8-K contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements include, but are not limited to, the volatility and level of crude oil and natural gas prices, the level and success rate of our exploration programs, our ability to maintain production rates and replace reserves, political and regulatory instability, and uncontrollable natural hazards. For further discussion of risk factors, see Item 1A. Risk Factors beginning on page 7 of the 2008 Form 10-K. Murphy undertakes no duty to publicly update or revise any forward-looking statements.
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