Murphy Oil announced that net income in the second quarter of 2010 was $272.3 million ($1.41 per diluted share) compared to net income of $158.8 million ($0.83 per diluted share) in the second quarter of 2009. Income improved in 2010 in both the upstream and downstream businesses of the Company. Upstream earnings improved in the 2010 quarter due to higher oil and natural gas sales volumes and sales prices, while downstream earnings in 2010 improved due to stronger U.S. retail marketing margins. Net income in the 2009 quarter included a $24.7 million after-tax charge ($0.13 per diluted share) associated with an anticipated reduction of the Company's working interest in the Terra Nova field, offshore Eastern Canada, $13.4 million of after-tax gains ($0.07 per diluted share) from insurance settlements for fire and hurricane damages in prior years at the Meraux, Louisiana, refinery, and a $2.1 million after-tax loss ($0.01 per diluted share in discontinued operations) for post-closing settlements and other adjustments on the sale of Ecuador properties that occurred in the first quarter 2009.
For the first six months of 2010, net income totaled $421.2 million ($2.18 per diluted share) compared to net income of $329.9 million ($1.72 per diluted share) for the same period in 2009. The six-month 2009 period included income from discontinued operations of $97.8 million ($0.51 per diluted share), primarily related to an after-tax gain of $103.6 million from the sale of Ecuador properties.
Second Quarter 2010 vs. Second Quarter 2009
Exploration and Production (E&P)
The Company's income from continuing exploration and production operations was $219.1 million in the second quarter of 2010 compared to $118.3 million in the same quarter of 2009. Income in the 2010 quarter exceeded 2009 primarily due to higher crude oil and natural gas sales prices and sales volumes in the current period. The 2009 quarter included a $24.7 million after-tax charge for an anticipated reduction in working interest at the Terra Nova field. Worldwide production totaled 189,951 barrels of oil equivalent per day in the second quarter 2010, a 33% increase from the same quarter in 2009. Total crude oil and gas liquids production was 131,983 barrels per day in the second quarter of 2010 compared to 118,145 barrels per day in the 2009 quarter, with the 12% increase primarily attributable to production at the Thunder Hawk field in the Gulf of Mexico and at the Azurite field, offshore Republic of the Congo, both of which came on production in the third quarter 2009. Additionally, Syncrude oil production was higher in 2010 than 2009 due to less downtime for maintenance in the current period. Oil production in Malaysia was lower in the 2010 period mostly due to a smaller entitlement percentage allocable to the Company at the Kikeh field, offshore Sabah. Crude oil and gas liquids sales volumes averaged 131,810 barrels per day in the second quarter of 2010 compared to 112,538 barrels per day in the 2009 quarter. The Company's worldwide crude oil and condensate sales prices averaged $64.68 per barrel for the second quarter of 2010 compared to $53.55 per barrel in the second quarter of 2009. Natural gas sales volumes averaged a Company record 348 million cubic feet per day in the second quarter of 2010 compared to 147 million cubic feet per day in the 2009 quarter. The 136% increase in natural gas sales volumes in 2010 was a result of production at a field offshore Sarawak, Malaysia, that started up in the third quarter of 2009, continued ramp-up of natural gas production volumes at the Tupper area in British Columbia, Canada, and higher third party gas demand from the Kikeh field, offshore Sabah, Malaysia. North American natural gas sales prices averaged $4.16 per thousand cubic feet (MCF) in the 2010 quarter compared to $3.25 per MCF in the same quarter of 2009. Natural gas from an offshore Sarawak field was sold at an average price of $5.10 per MCF during the second quarter 2010. Exploration expenses were $53.2 million in the second quarter of 2010 compared to $35.0 million in the same period of 2009, with the increase mainly attributable to a combination of remaining dry hole costs for the Batai well in Malaysia, geophysical costs in the Eagle Ford shale area of South Texas, the Gulf of Mexico and Republic of the Congo, and early exploration activities in Suriname.
Corporate functions incurred net costs of $30.6 million in the 2010 second quarter compared to net benefits of $14.8 million in the 2009 second quarter, with the unfavorable result in 2010 related to losses on transactions denominated in foreign currencies in the current quarter compared to gains on these transactions in the 2009 quarter. The significant weakening of the U.S. dollar versus certain foreign currencies during the second quarter 2009 led to large foreign exchange gains in the prior year, primarily in the United Kingdom. After-tax foreign currency effects were losses of $1.6 million in the 2010 quarter compared to gains of $33.6 million in the same 2009 quarter. Net interest expense was higher in the 2010 quarter primarily due to lower interest costs capitalized to oil and natural gas development projects. Administrative costs were also higher in 2010 primarily due to more employee compensation expense.
First Six Months 2010 vs. First Six Months 2009
Exploration and Production (E&P)
The Company's E&P business earned $466.1 million from continuing operations in the first six months of 2010 compared to earnings of $168.6 million in the same period of 2009. Earnings in 2010 were favorably affected by significantly higher crude oil and natural gas sales prices compared to a year ago. The Company also benefited from higher crude oil and natural gas sales volumes in 2010 compared to 2009. The 2009 period included the aforementioned $24.7 million charge after taxes for an anticipated redetermination at the Terra Nova field. Worldwide production amounted to 193,071 barrels of oil equivalents per day during the first six months of 2010, 28% higher than the same period a year ago. Crude oil and gas liquids production for the first six months of 2010 averaged 135,502 barrels per day compared to 128,673 barrels per day in 2009. The 5% oil production increase in 2010 was mostly caused by higher crude oil produced at the Thunder Hawk field in the Gulf of Mexico and the Azurite field, offshore Republic of the Congo. Natural gas sales volumes were 345 million cubic feet per day in 2010 compared to 129 million cubic feet per day in 2009, with the 167% increase resulting from new volumes produced at a Sarawak natural gas field, offshore Malaysia, ramp-up of gas production at the Tupper area in British Columbia, and higher sales volumes from the Kikeh field, offshore Sabah, Malaysia. Crude oil and condensate sales prices averaged $64.59 per barrel in the 2010 period compared to $48.01 per barrel in 2009. North American natural gas was sold at an average price of $4.61 per MCF in 2010, compared to $3.89 per MCF in 2009. Sarawak natural gas production was sold at an average of $4.87 per MCF during 2010. Exploration expenses were $119.5 million in 2010 compared to $146.1 million in 2009. The lower costs in the 2010 period primarily resulted from dry hole costs related to unsuccessful wildcat drilling in the prior year in Australia and the United States, more geophysical costs in 2009 in Suriname, and higher leasehold amortization in 2009 at the Tupper West area in Western Canada. These favorable impacts were somewhat offset by higher costs in 2010 for geophysical activities and leasehold amortization at the Eagle Ford shale area in South Texas and unsuccessful exploration drilling in Malaysia.
David M. Wood, President and Chief Executive Officer, commented, "Although our Gulf of Mexico exploration program has been deferred due to the government imposed drilling moratorium, we have continued to remain very active onshore North America. In the Eagle Ford Shale in South Texas, we completed additional wells in the second quarter and are currently drilling our eighth and ninth wells in the play. Beginning in the third quarter of 2010, we will have three rigs operating in the Eagle Ford shale, where our emphasis will be primarily in the liquids rich areas. In the Montney play in British Columbia, Canada, we continue to drive down drilling and completion costs, while producing strong well results, which is crucial in today's tough gas pricing environment. We have six rigs operating in Canada, five in the Montney and one at Seal. Construction of our 180 million cubic feet per day capacity gas plant at Tupper West is well under way with first gas expected in the first half of 2011. In the fourth quarter 2010, we will drill three exploratory wells in Republic of the Congo, using a rig we have redeployed from the Gulf of Mexico, and will also drill prospects in Indonesia and Suriname. We have commenced the process of selling our U.S. refining and U.K. R&M operations.
"Total production in the third quarter of 2010 should average 180,000 barrels of oil equivalent per day, but sales volumes are projected to average 178,000 barrels of oil equivalent per day. Third quarter production is estimated to be less than previously anticipated mostly due to unplanned downtime at Kikeh in Malaysia and continued delays in bringing on new wells at the Azurite development in Republic of the Congo. At Kikeh, a failure of a coiled tubing unit during a workover has caused us to wait for a rig to arrive in the fourth quarter to complete our workover program. Currently, the facility is producing at temporarily reduced rates near 100,000 barrel equivalents per day. Three wells are currently onstream at Azurite with additional wells expected to be brought onstream through the fourth quarter. Due to the issues mentioned, we are lowering our 2010 yearly average production forecast to 194,000 barrels of oil equivalent per day. We currently expect earnings in the third quarter to be between $1.10 and $1.15 per diluted share. This earnings projection includes a contribution from our refining and marketing business of approximately $70 million, and total exploration expense ranging from $80 to $90 million. Projected results for the third quarter could be affected by commodity prices, drilling results, timing of oil sales, refining and marketing margins and foreign currency effects."