MURPHY OIL CORP /DE - 10-K - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Edgar Glimpses Via Acquire Media NewsEdge) Overview Murphy Oil Corporation is a worldwide oil and gas exploration and production company with petroleum marketing operations in the United States and refining and marketing operations in the United Kingdom. A more detailed description of the Company's significant assets can be found in Item 1 of this Form 10-K report.

Murphy generates revenue by selling oil and natural gas production to customers in the United States, Canada, Malaysia and other countries. Additionally, the Company generates revenue by selling refined petroleum and ethanol products at hundreds of locations in the United States and the United Kingdom. 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 U.K. refinery feedstocks, natural gas is purchased for fuel at its U.K. refinery, U.S. ethanol plants and at worldwide 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 and note holders.

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 58% of the total hydrocarbons produced on an energy equivalent basis (one barrel of crude oil equals six thousand cubic feet of natural gas) by the Company in 2012. In 2013, the Company's ratio of hydrocarbon production represented by oil is expected to be approximately two-thirds oil, one-third gas, due to a combination of growing oil production and declining North American natural gas production. If the prices for crude oil and natural gas should weaken in 2013 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.

Worldwide oil prices in 2012 were generally comparable to 2011, while the sale prices for natural gas produced in North America was significantly weaker than the prior year. The sales price for a barrel of West Texas Intermediate (WTI) crude oil averaged $94.15 in 2012, $95.11 in 2011 and $79.61 in 2010. The NYMEX natural gas price per million British Thermal Units (MMBTU) averaged $2.83 in 2012, $4.03 in 2011 and $4.38 in 2010. While the price of WTI fell slightly in 2012, certain other benchmark oil prices, such as Dated Brent, experienced small increases during the year. Natural gas prices fell in 2012 primarily due to continued expansion in North American gas supply and secondly due to a warmer than normal winter season in 2012 in the U.S. and Canada. Gas supplies grew primarily due to a number of expanding North American unconventional gas resource plays. Worldwide oil prices were significantly higher in 2011 than 2010, but North American natural gas prices were weaker in 2011 than in the prior year. Crude oil prices rose in 2011 primarily due to a combination of recovering demand and unrest in the oil-rich Middle East and Northern Africa.

While the 2011 prices of WTI crude oil rose almost 20% compared to the prior year, crude oil sold based on other worldwide benchmark prices, such as Brent and Tapis, rose even more than WTI in that year. The 2011 rise in prices of WTI crude oil, which is only used as a benchmark in North America, was held back compared to other worldwide benchmark price increases due to a somewhat temporary crude oil dislocation discount and a bit of supply/demand disparity in the continental U.S. during 2011. The disparity between crude oil and natural gas prices in North America continued to widen during both 2012 and 2011 on an energy equivalent basis due to gas production growth that exceeded demand. U.S.

crude oil prices in early 2013 have been similar to 2012 average prices, while natural gas prices in North America in 2013 have thus far been slightly above the 2012 levels due to cold temperatures across much of the Northern U.S. during the early winter season.

27 -------------------------------------------------------------------------------- Table of Contents Results of Operations Murphy Oil's results of operations, with associated diluted earnings per share (EPS), for the last three years are presented in the following table.

Years Ended December 31 (Millions of dollars, except EPS) 2012 2011 2010 Net income $ 970.9 872.7 798.1 Diluted EPS 4.99 4.49 4.13 Income from continuing operations $ 964.1 729.5 749.1 Diluted EPS 4.95 3.75 3.88 Income from discontinued operations $ 6.8 143.2 49.0 Diluted EPS 0.04 0.74 0.25 Murphy Oil's net income in 2012 increased 11% compared to 2011 primarily due to higher earnings for continuing exploration and production (E&P) operations, partially offset by lower earnings for continuing refining and marketing operations (R&M), lower income from discontinued operations, and higher net costs of Corporate activities that were not allocated to operating segments.

Net income in 2011 was 9% higher than 2010, with the improvement primarily attributable to better earnings for R&M continuing operations, higher income from discontinued operations, which was essentially attributable to strong U.S.

refining results prior to sale of these assets, and lower net costs for Corporate activities. Lower E&P earnings for continuing operations in 2011, primarily associated with a large impairment charge in Republic of the Congo, somewhat offset these favorable results in other areas.

Further explanations of each of these variances are found in more detail in the following sections.

2012 vs. 2011 - Net income in 2012 was $970.9 million ($4.99 per diluted share) compared to $872.7 million ($4.49 per diluted share) in 2011. Income from continuing operations was $964.1 million ($4.95 per diluted share) in 2012, up from $729.5 million ($3.75 per diluted share) in 2011. Earnings for 2012 increased primarily due to a combination of lower impairment charges, income tax benefits, higher crude oil sales volumes, lower exploration expenses and higher U.K. R&M earnings. These were partially offset by lower North American natural gas sales prices, lower U.S. retail marketing margins, and unfavorable effects of foreign exchange compared to the prior year. Net income in 2012 and 2011 included income from discontinued operations of $6.8 million ($0.04 per diluted share) and $143.2 million ($0.74 per diluted share), respectively. The stronger results for discontinued operations in 2011 were primarily associated with operating income and a net gain on disposal of two U.S. refineries (Meraux, Louisiana and Superior, Wisconsin) and associated marketing assets which were sold in 2011.

By business unit, E&P income from continuing operations improved $290.8 million in 2012, primarily due to higher crude oil production, lower impairment expense in Republic of the Congo, income tax benefits associated with exploration activities in Republic of the Congo and Suriname, and lower exploration expenses. E&P operating results were unfavorably affected in 2012 compared to the prior year by lower North American natural gas sales prices and higher expenses for production, depreciation and administration. Income from R&M continuing operations was $32.7 million lower in 2012, with the reduction mostly attributable to lower earnings, including an impairment charge, for U.S. ethanol production operations, plus lower U.S. retail fuel margins, with these more than offsetting significantly better U.K. refining margins in the current year. The net costs of corporate activities were higher by $23.5 million in 2012, mostly attributable to unfavorable effects of transactions denominated in foreign currencies. To a lesser degree, the 2012 corporate net costs were unfavorably affected by lower interest income and higher administrative expenses.

Sales and other operating revenues grew $1.0 billion in 2012 compared to 2011 due to higher crude oil sales volumes for the E&P business, plus slightly larger sales volumes for both the U.S. and U.K. R&M continuing operations. Gain (loss) on sale of assets was $23.9 million less in 2012 than 2011 because the earlier year 28 -------------------------------------------------------------------------------- Table of Contents included a $23.1 million gain on sale of natural gas storage assets in Spain.

Interest and other operating income was unfavorable by $22.0 million in 2012 compared to 2011 mostly due to an $18.4 million unfavorable pretax variance from the effects of transactions denominated in foreign currencies, plus interest income in 2011 of $2.7 million associated with a recovery of Federal royalties for certain deepwater Gulf of Mexico fields. The expense associated with crude oil and product purchases increased by $574.0 million in 2012 compared to 2011 primarily due to higher costs for wholesale gasoline and other motor fuels which were purchased for resale at the Company's retail fueling stations in the U.S.

and U.K. Operating expenses were $162.6 million more in 2012 than 2011 due to a combination of higher oil and natural gas production costs and higher costs for U.S. retail gasoline station operations. Exploration expenses were $108.4 million lower in 2012 compared to 2011 due to more drilling success in 2012, plus lower geophysical expense in the Gulf of Mexico, Malaysia, Brunei and the Kurdistan region of Iraq. Selling and general expenses were $57.0 million more in 2012 than in 2011 primarily due to higher employee compensation and professional services costs. Depreciation, depletion and amortization expense rose $295.8 million in 2012 versus 2011 due to higher crude oil and natural gas sales volumes in 2012 and higher E&P per-unit depreciation rates. Impairment of properties was $107.6 million lower in 2012 than in 2011, primarily due to a smaller impairment charge in Republic of the Congo in 2012, partially offset by a writedown in the current year of the Hereford, Texas, ethanol production facility. Accretion of asset retirement obligations was $4.6 million more in 2012 than 2011 primarily due to higher discounted abandonment liabilities for wells drilled in 2012 in Malaysia, higher estimated abandonment costs for wells in the Gulf of Mexico, and higher future reclamation costs for synthetic oil operations at Syncrude. Redetermination of working interest at the Terra Nova field was a $5.4 million benefit in 2011 due to nonrecurring income achieved upon final settlement of the redetermination process in early 2011. Interest expense in 2012 was $1.7 million less than 2011 primarily due to lower average interest rates paid on borrowed funds in the later year, partially offset by the effects of higher average outstanding debt levels in the most recent year. The benefit from capitalized interest was $24.0 million higher in 2012 than the prior year due to larger levels of financing costs allocated to ongoing oil development projects in the later year. Income tax expense in 2012 was $104.2 million less than 2011 primarily due to U.S. income tax benefits of $108.3 million in 2012 associated with exploration activities in Republic of the Congo and Suriname. The consolidated effective tax rate was 40.6% in 2012 compared to 51.1% in 2011, with the lower rate in the later year caused by the U.S. tax benefits for Republic of the Congo and Suriname, a lower percentage of earnings in higher tax jurisdictions in 2012, and lower current year exploration and other expenses in foreign jurisdictions where no income tax benefit can presently be recognized due to no assurance that these expenses will be realized in 2012 or future years to reduce taxes owed. The tax rates in both 2012 and 2011 were 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 exceeded 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 Company's uncertain ability to obtain tax benefits for these costs in 2012 or future years. Income from discontinued operations was $6.8 million ($0.04 per diluted share) in 2012 and $143.2 million ($0.74 per diluted share) in 2011. Income from discontinued operations in both years included operating results for oil and gas production operations in the U.K., but discontinued operations in 2011 included operating profits of $113.1 million associated with the two U.S. petroleum refineries sold in late 2011, plus an $18.7 million after-tax gain on sale of these refineries.

2011 vs. 2010 - Net income in 2011 totaled $872.7 million ($4.49 per diluted share) compared to $798.1 million ($4.13 per diluted share) in 2010. Income from continuing operations was $729.5 million ($3.75 per diluted share) in 2011 compared to $749.1 million ($3.88 per diluted share) in 2010. The reduction in 2011 income from continuing operations in comparison to 2010 was primarily attributable to an impairment charge of $368.6 million in 2011 to reduce the carrying value of the Azurite oil field offshore Republic of the Congo. This was mostly offset by higher oil prices and stronger U.S. retail marketing margins in the later year. The net cost of corporate activities not allocated to the operating segments was lower in 2011 than in 2010. Net income in 2011 included income from discontinued operations of $143.2 million ($0.74 per diluted share) compared to income from discontinued operations of $49.0 million ($0.25 per diluted share) in 2010. The higher income for discontinued operations in 2011 was primarily associated with both strong operating income and a gain on sale of two U.S. refineries and associated marketing assets which were sold in 2011.

29 -------------------------------------------------------------------------------- Table of Contents E&P income in 2011 was $162.2 million lower than 2010, primarily attributable to the $368.6 million impairment charge at the Azurite oil field in Republic of the Congo. Other unfavorable impacts in 2011 included higher dry hole costs compared to 2010, lower crude oil sales volumes, lower North American natural gas sales prices and higher extraction costs for oil and gas produced in 2011. E&P results in 2011 benefited from a 41% higher average sales prices for crude oil produced and a 34% higher sales prices for natural gas produced offshore Sarawak, Malaysia. Income from R&M continuing operations was $59.7 million higher in 2011 compared to 2010, essentially attributable to stronger U.S. retail gasoline marketing margins of more than $0.04 per gallon and larger profits on sales of merchandise in the U.S. retail marketing business. The net costs of corporate activities were $82.9 million less in 2011 than 2010 primarily due to gains from transactions denominated in foreign currencies in 2011 compared to losses on such transactions in 2010. During 2011 the U.S. dollar generally strengthened in comparison to the Malaysian ringgit, which provided a favorable foreign currency impact to the Company's earnings due to fewer U.S. dollars being required to pay 2011 and future income taxes owed in the local currency.

Sales and operating revenues were $7.5 billion more in 2011 than 2010 primarily due to higher prices realized on crude oil production and gasoline and other refined products sold by the Company. Gain on sale of assets classified in continuing operations was $21.8 million more in 2011 than 2010 principally due to a profit on sale of gas storage assets in Spain in 2011. Interest and other income (loss) in 2011 was favorable $90.6 million compared to 2010 principally due to improved income effects from transactions denominated in foreign currencies. Additionally, the Company collected higher interest income on invested cash balances in 2011 primarily due to larger average invested balances during the year. Crude oil and product purchases expense was $6.5 billion more in 2011 than 2010 due to higher costs of crude oil feedstocks at the Milford Haven, Wales refinery, higher costs for gasoline purchased for resale in the U.S. retail marketing operations and an increase in volume of merchandise purchased for resale at U.S. retail gasoline stations. Operating expenses in 2011 were $313.3 million more than 2010 mostly due to higher costs associated with the Company's production of oil and natural gas in 2011, plus higher operating expenses at U.S. retail marketing stations, and higher power and other costs at the Milford Haven, Wales refinery. Exploration expense in 2011 was $213.3 million above 2010 primarily due to higher dry hole costs associated with unsuccessful exploratory drilling activities in Brunei, Indonesia, Canada and Suriname. Selling and general expenses rose $41.0 million in 2011 compared to 2010 primarily due to a combination of higher costs for employee compensation and professional services. Depreciation, depletion and amortization expense was down $12.4 million in 2011 mostly due to fewer barrels of oil equivalent produced in 2011 compared to 2010. Impairment of properties of $368.6 million in 2011 was attributable to a charge to reduce the net book value of the Azurite oil field to fair value. The charge was necessitated by a reduction of proved oil reserves at this field at year-end 2011. Accretion of asset retirement obligations increased $5.1 million in 2011, primarily due to future abandonment costs to be incurred on oil and gas development wells drilled in the Eagle Ford Shale and Montney areas in 2011, and higher estimated abandonment costs for existing wells in the Gulf of Mexico and offshore Malaysia and for synthetic oil operations at Syncrude in Western Canada. The income effect of the redetermination of the Company's working interest at the Terra Nova field, offshore Eastern Canada, was favorable $23.9 million in 2011 compared to 2010.

The final settlement for the redetermination was made in early 2011 at a net cost to the Company that was $5.4 million less than previously estimated. The benefit from this reduced settlement payment was recognized in 2011. The net cost of $18.6 million in 2010 related to the portion of Terra Nova's operating results in 2010 that were estimated to be owed to other partners upon final settlement. Due to the redetermination process, the Company's working interest at Terra Nova was reduced from 12.0% to 10.475%. Interest expense in 2011 was $2.7 million more than 2010 primarily due to interest associated with tax reassessments in Canada in 2011. Interest capitalized to oil and gas development projects in 2011 was $3.3 million below 2010 due to cessation of interest capitalized upon commencement of production at the Tupper West area in Western Canada in the first quarter 2011. Income tax expense was $186.6 million more in 2011 than 2010 due to higher pretax income in 2011 plus higher exploration and impairment expenses in 2011 for which no tax benefit was recognizable by the Company. The effective tax rate on a consolidated basis increased from 43.5% in 2010 to 51.1% in 2011 due to a larger percentage of earnings in higher tax jurisdictions in 2011 and due to higher exploration, impairment and other expenses in foreign jurisdictions where no income tax benefits were recognized due to no assurance that 30 -------------------------------------------------------------------------------- Table of Contents these expenses would be realized in 2011 or future years to reduce taxes owed.

The tax rates in both 2011 and 2010 were higher than the U.S. federal statutory rate of 35.0% due to a combination of U.S. state income taxes, certain foreign tax rates that exceeded 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 Company's uncertain ability to obtain tax benefits for these expenses in 2011 or future years. Income from discontinued operations was $94.2 million higher in 2011 than 2010 due to stronger U.S. refining margins in 2011 prior to the sale of the refineries near the end of the third quarter of 2011. Additionally, 2011 discontinued operations included a pretax gain on sale of the two U.S. refineries of $18.7 million.

Segment Results - In the following table, the Company's results of operations for the three years ended December 31, 2012, 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) 2012 2011 2010 Exploration and production - continuing operations United States $ 168.0 152.7 72.7 Canada 208.1 328.0 213.8 Malaysia 894.2 812.7 659.4 Republic of the Congo (241.1 ) (385.3 ) (77.2 ) Other (124.2 ) (293.9 ) (92.3 ) 905.0 614.2 776.4 Refining and marketing - continuing operations United States 105.4 223.6 165.3 United Kingdom 52.2 (33.3 ) (34.7 ) 157.6 190.3 130.6 Corporate and other (98.5 ) (75.0 ) (157.9 ) Income from continuing operations 964.1 729.5 749.1 Income from discontinued operations 6.8 143.2 49.0 Net income $ 970.9 872.7 798.1 Exploration and Production - Earnings from exploration and production (E&P) continuing operations were $905.0 million in 2012, $614.2 million in 2011 and $776.4 million in 2010.

Income for E&P continuing operations in 2012 was $290.8 million more than in 2011. The increase was primarily attributable to lower impairment charges of $168.6 million in Republic of the Congo in 2012, favorable tax benefits of $108.3 million in the current year for exploration activities in Republic of the Congo and Suriname, plus higher crude oil and natural gas sales volumes and stronger crude oil sales prices in the current year. The Company's average realized sales price for crude oil, condensate and gas liquids in 2012 for continuing operations increased $1.40 per barrel over 2011. The Company's average natural gas sales prices in Sarawak Malaysia were also higher in 2012 than 2011, but natural gas sales prices in 2012 in North America were significantly below 2011 levels. Crude oil and liquids sales volumes increased 12% in 2012 while natural gas sales volumes rose 7%. The increase in hydrocarbon sales volumes in 2012 led to higher expenses for production and depreciation of $104.5 million and $288.4 million, respectively. The 2012 year had less exploration expenses of $108.5 million compared to 2011, essentially due to lower expenses related to unsuccessful exploratory drilling and geophysical activities. Crude oil sales volumes increased in 2012 in the U.S. primarily due to higher volumes produced in the Eagle Ford Shale area of South Texas.

Conventional oil sales volumes in Canada in 2012 were less than 2011 primarily due to lower gross production at the Terra Nova field, where more downtime for maintenance occurred in the current year. Synthetic oil sales volumes at Syncrude increased in 2012 due to higher gross production compared to 2011.

Sales volumes for crude oil produced in Malaysia were higher in 31-------------------------------------------------------------------------------- Table of Contents 2012 primarily due to new wells brought on production at the Kikeh field offshore Sabah. Crude oil sales volumes decreased in 2012 in Republic of the Congo due to field decline and a well failure at the Azurite field. Natural gas sales volumes in 2012 increased compared to the prior year principally due to more wells producing for a longer period in the Tupper area in Western Canada and higher gas volumes produced in the Eagle Ford Shale.

E&P income in 2011 was $162.2 million less than in 2010 primarily due to a $368.6 million impairment charge to reduce the carrying value of the Azurite oil field to fair value at year-end 2011. The 2011 period also had higher exploration expense, lower crude oil sales volumes and lower North American natural gas sales prices. However, 2011 benefited from higher oil and Sarawak natural gas sales prices and higher natural gas sales volumes. The Company's realized crude oil sales prices for continuing operations averaged $27.43 per barrel more in 2011 than 2010. North American natural gas sales prices in 2011 were $0.26 per MCF below 2010 levels, but natural gas sales prices from fields offshore Sarawak were higher in 2011 by $1.79 per MCF. Crude oil, condensate and gas liquids sales volumes from continuing operations were 21% lower in 2011 than in 2010, compared to a decrease in oil production volumes of 19% in 2011. Oil sales volumes declined more than oil production volumes during 2011 primarily due to the timing of scheduling oil sales transactions at the Kikeh field offshore Malaysia. Sales volumes at Kikeh were below production levels in 2011 due to an increase in the volume of unsold barrels at the field at year-end 2011, while in 2010, Kikeh sales volumes exceeded production. U.S. crude oil sales volumes were lower in 2011 than 2010 principally due to less production at the Thunder Hawk field in the Gulf of Mexico. Lower crude oil sales volumes in Canada in 2011 were mostly attributable to production issues and a lower Company working interest percentage in 2011 at the Terra Nova field, but this was partially offset by higher sales volumes at the Seal heavy oil field in Alberta.

Crude oil sales volumes at Kikeh in 2011 fell compared to 2010 due to lower annual production in 2011 caused by well downtime for mechanical issues. Sales of crude oil and condensate increased at fields offshore Sarawak in 2011 due to higher volumes produced during the year. Crude oil sales volumes in Republic of the Congo fell in 2011 due to production decline at the Azurite field. Natural gas sales volumes for continuing operations increased 29% in 2011 and the improvement was primarily attributable to higher gas volumes produced during 2011 at the Tupper West area in Western Canada following start-up in the first quarter of the year. Natural gas sales volumes also improved in 2011 at the Tupper area in Canada and at fields offshore Sarawak; both of these areas had active development programs during 2011. Natural gas sales volumes were lower during 2011 at the Kikeh field principally due to less volumes produced because of mechanical issues with wells.

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-51 and F-52 of this Form 10-K report. Average daily production and sales rates and weighted average sales prices are shown on page 5 of the 2012 Annual Report.

A summary of oil and gas revenues, including intersegment sales that are eliminated in the consolidated financial statements, is presented in the following table.

(Millions of dollars) 2012 2011 2010 United States - Oil and gas liquids $ 976.1 648.8 557.6 - Natural gas 54.2 71.1 87.0 Canada - Conventional oil and gas liquids 411.7 505.6 388.6 - Synthetic oil 463.1 506.6 378.6 - Natural gas 209.8 280.2 132.1 Malaysia - Oil and gas liquids 1,946.0 1,583.0 1,531.1 - Natural gas 481.1 461.3 307.1 Republic of the Congo - oil 57.6 148.8 156.7 Total oil and gas revenues $ 4,599.6 4,205.4 3,538.8 The Company's total crude oil, condensate and natural gas liquids production averaged 112,591 barrels per day in 2012, compared to 103,160 barrels per day in 2011 and 126,927 barrels per day in 2010.

32-------------------------------------------------------------------------------- Table of Contents United States crude oil production averaged 26,090 barrels per day in 2012, an annual record for the Company in the U.S., and an increase from 17,148 barrels per day in 2011. The U.S. increase was primarily attributable to an ongoing development drilling program in the Eagle Ford Shale area in South Texas. Heavy oil production in the Western Canada Sedimentary Basin of 7,241 barrels per day in 2012 was about flat with 2011. Crude oil production offshore Canada fell from 9,204 barrels per day in 2011 to 6,986 barrels per day in 2012 essentially due to more downtime for maintenance at the Terra Nova field and well decline at the Hibernia field. Synthetic oil production of 13,830 barrels per day in 2012 slightly exceeded 2011 volumes of 13,498 per day. Crude oil and liquids production in Malaysia averaged 52,663 barrels per day in 2012, up from 48,551 barrels per day in 2011, with the increase mainly due to additional wells brought on production at the Kikeh field. Oil production in Republic of the Congo fell to 2,078 barrels per day in 2012 after averaging 4,989 barrels per day in 2011, with the reduction due to a well that went off production during 2012 and normal decline at other wells in the field. Crude oil production in the U.K. was 3,458 barrels per day in 2012 compared to 2,423 barrels per day in 2011. The U.K. increase in 2012 was primarily at Schiehallion, where better overall performance more than offset lower volumes at Mungo/Monan. Expected sales of all U.K. oil and natural gas operations in early 2013 led the Company to report these U.K. E&P activities as discontinued operations for all periods presented in the consolidated financial statements.

United States oil production decreased from 20,114 barrels per day in 2010 to 17,148 barrels per day in 2011 with the lower volumes mostly caused by field decline at Thunder Hawk that was primarily due to a delay in development drilling operations in 2010 and 2011 following the Macondo incident in April 2010. The production decline at Thunder Hawk was partially offset by higher oil volumes produced in 2011 at the Eagle Ford Shale area in South Texas. Production of heavy oil in Western Canada was 7,264 barrels per day in 2011, up from 5,988 barrels per day in 2010, primarily due to ongoing drilling operations at the Seal area in Alberta. Oil production offshore Canada fell from 11,497 barrels per day in 2010 to 9,204 barrels per day in 2011 primarily due to field decline at Terra Nova and a reduction of the Company's working interest at this field from 12.0% in 2010 to 10.475% in 2011. Synthetic oil operations at Syncrude had net production of 13,498 barrels per day in 2011, up from 13,273 barrels per day in 2010, with the increase caused by a lower royalty rate in 2011 due to higher costs incurred for the operations. Oil production in Malaysia decreased from 66,897 barrels per day in 2010 to 48,551 barrels per day in 2011, primarily due to lower production at the Kikeh field. Mechanical issues at Kikeh led to certain wells being down for a portion of 2011. Oil production in Malaysia was favorably affected in 2011 by higher condensate and other gas liquids produced at gas fields offshore Sarawak. The Azurite field offshore Republic of the Congo averaged 4,989 barrels per day in 2011, down from 5,820 barrels per day in 2010 due to faster than expected well decline. Oil production from discontinued operations in the U.K. was 2,423 barrels per day in 2011, down from 3,295 barrels per day in 2010, with the decline primarily due to more downtime at the Schiehallion and Mungo/Monan fields during the later year.

Worldwide sales of natural gas were a Company record 490.1 million cubic feet (MMCF) per day in 2012, after averaging 457.4 MMCF per day in 2011 and 356.8 MMCF per day in 2010.

Natural gas sales volumes in the U.S. were 53.0 MMCF per day in 2012, up from 2011 production of 47.2 MMCF per day as higher production in the Eagle Ford Shale area more than offset declines at fields in the Gulf of Mexico. Natural gas volumes in Western Canada increased from 188.8 MMCF per day in 2011 to 217.0 MMCF per day in 2012 essentially due to higher gas volumes produced at the Tupper area, as more wells were on production at Tupper West during 2012.

Natural gas sales volumes offshore Sarawak, Malaysia, averaged 174.3 MMCF per day in 2012 following volumes of 177.0 MMCF per day in 2011. Gas sales at the Kikeh field averaged 42.4 MMCF per day in 2012, up from 40.5 MMCF per day the prior year. Natural gas sales volumes in the U.K. reported as discontinued operations fell from 3.9 MMCF per day in 2011 to 3.4 MMCF per day in 2012 due to well decline at the Mungo/Monan field during the later year.

Natural gas production in the U.S. averaged 47.2 MMCF per day in 2011, compared to 53.0 MMCF per day in 2010. The lower volume in 2011 was primarily attributable to the Thunder Hawk field where production declined during 2011 due to delay in development drilling operations following the Macondo incident in April 2010.

33 -------------------------------------------------------------------------------- Table of Contents Natural gas production in Canada rose from 85.6 MMCF per day in 2010 to 188.8 MMCF per day in 2011 primarily due to start up of production at the Tupper West area in Western Canada in the first quarter 2011. Gas sales volumes also increased in 2011 at the nearby Tupper area due to development drilling activities during the year. Natural gas production in Malaysia rose to 217.4 MMCF per day in 2011 compared to 212.7 MMCF per day in 2010. Natural gas sales volumes during 2011 at Sarawak and Kikeh averaged 176.9 MMCF per day and 40.5 MMCF per day, respectively. Gas sales volumes rose 22.4 MMCF per day at Sarawak in 2011 due to higher demand from the local purchaser, while Kikeh gas volumes fell 17.7 MMCF per day in 2011 due to lower demand and wells down for mechanical repairs for a portion of the year. Natural gas production from discontinued operations in the U.K. fell from 5.5 MMCF per day in 2010 to 3.9 MMCF per day in 2011 primarily due to more downtime for repairs at the Amethyst field during 2011.

The Company's average worldwide realized sales price for crude oil, condensate and gas liquids from continuing operations was $95.58 per barrel in 2012 compared to $94.18 per barrel in 2011 and $66.75 per barrel in 2010.

The average realized crude oil sales price for continuing operations increased 1% in 2012 compared to 2011. The higher realized price for 2012 was favorable to the 1% reduction in West Texas Intermediate (WTI) sales price between the years.

Other benchmark oil prices used for sale of Company crude oil, such as Dated Brent, performed more favorably than WTI. During 2012, the Company began to sell its Kikeh crude oil based on a new Kikeh benchmark price, where it had been sold since late 2010 on a Brent crude oil benchmark. Compared to 2011, the Company's average 2012 crude oil sales prices fell 1% in the U.S. to average $102.60 per barrel. Heavy oil sales prices in Canada fell 19% in 2012 to an average of $46.45 per barrel. Offshore Canada oil sold at $112.08 per barrel in 2012, an increase of 2%. Canadian synthetic crude oil sold for 11% less in 2012 and averaged $91.85 per barrel. The crude oil sales price in Malaysia increased 8% to an average price of $97.29 per barrel in 2012. Crude oil sold in Republic of the Congo increased 4% to a price of $107.26 per barrel in 2012.

The Company's average realized oil sales price of $94.18 in 2011 for continuing operations was an increase of 41% compared to 2010. The average price of WTI crude oil rose 19% during 2011. The Company's average oil price increased more than WTI because other worldwide benchmark prices rose more than WTI in 2011.

Dated Brent prices, for example, rose 40% during 2011. Crude oil prices strengthened in 2011 due to an improvement in energy demand in association with a slowly recovering worldwide economy and unrest in Northern Africa and the Middle East during 2011 that caused concern in the oil markets about the potential for supply disruptions. Compared to 2010, the Company's average 2011 crude oil sales prices in the U.S. rose 36% to $103.92 per barrel; heavy oil prices in Canada sold for 14% more and averaged $57.00 per barrel; offshore Canada prices increased 43% to $110.02 per barrel; synthetic crude oil sold for 32% more at $102.94 per barrel; crude oil in Malaysia was up 48% and averaged $90.14 per barrel; and crude oil in Republic of the Congo sold at $103.02 per barrel in 2011, an increase of 38% from 2010.

The Company's North American natural gas prices retracted in 2012 compared to 2011, while prices in other areas were a bit stronger in 2012. North American natural gas sales prices were hurt by an oversupply of gas caused by both a growing profile of unconventional gas production on the continent and an unusually warm winter season in the primary gas consuming markets in the U.S.

during 2012. The Company's average sales prices for natural gas in North America decreased 35% to $2.65 per thousand cubic feet (MCF) in 2012, which was composed of a 34% decline to $2.76 per MCF in the U.S. and a 36% decline to $2.62 per MCF in Canada. Natural gas produced offshore Sarawak sold for 6% more in 2012 than in 2011 and averaged $7.50 per MCF in the later year.

Natural gas sales prices in North America in 2011 did not generally increase in concert with crude oil prices during that year. A growing gas supply from unconventional sources such as shale operations kept gas prices in check during 2011. The Company's average realized North American natural gas sales price was $4.08 MCF in 2011, a decline of 6% from the $4.34 per MCF realized in 2010.

Natural gas produced in 2011 offshore Sarawak was sold at an average price of $7.10 per MCF, an increase of 34% from the $5.31 per MCF realized during 2010.

34 -------------------------------------------------------------------------------- Table of Contents Based on 2012 sales volumes and deducting taxes at marginal rates, each $1.00 per barrel and $0.10 per MCF fluctuation in prices would have affected 2012 earnings from exploration and production continuing operations by $26.4 million and $12.2 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 for continuing operations were $1,114.8 million in 2012, $1,010.3 million in 2011 and $852.6 million in 2010. These amounts are shown by major operating area on pages F-51 and F-52 of this Form 10-K report. Costs per equivalent barrel during the last three years are shown in the following table.

(Dollars per equivalent barrel) 2012 2011 2010 United States $ 19.75 18.05 12.46 Canada Excluding synthetic oil 9.00 8.65 8.45 Synthetic oil 44.27 47.91 42.61 Malaysia 12.78 13.66 9.31 Republic of the Congo 90.08 26.04 31.30 Worldwide - excluding synthetic oil 13.71 13.16 10.39 Production expense per equivalent barrel in the U.S. increased in 2012 compared to 2011 due to a significantly larger proportion of production in the later year coming from the Eagle Ford Shale in South Texas, where the average per-barrel cost exceeded the U.S. average. In 2013 and beyond, the Company anticipates the per-barrel cost for Eagle Ford Shale production to be below the 2012 U.S.

average cost. Cost per barrel for Canada conventional oil and gas operations, excluding synthetic oil, was higher in 2012 than 2011 due to additional maintenance costs in the current year at the Terra Nova field. This Canadian cost increase was tempered by higher natural gas production at the lower than average cost Tupper area. Lower future Tupper area production, attributable to reduced drilling levels caused by depressed sales prices, is expected to lead to increases in per-unit production expense at Tupper as well as for overall conventional Canada production in 2013. The reduction in production costs per barrel for synthetic oil operations in 2012 compared to 2011 was attributable to lower natural gas power costs in the current year. Due to anticipated additional government emission and other environmental requirements in 2013 and beyond, the Company expects synthetic oil production expense to be higher on a per-barrel basis in future years. Production expense in Malaysia declined in 2012 compared to 2011 due to less well maintenance and workover costs at the Kikeh field.

Per-barrel production expense in 2012 in Republic of the Congo was significantly higher than 2011 due to lower production levels and unsuccessful workover costs at a well in the Azurite field.

Production expense per equivalent barrel in the U.S. increased in 2011 compared to 2010 due to lower volumes produced at the Thunder Hawk field and higher facility rental costs in the early days of the Eagle Ford Shale operation as production ramped up. The per-unit cost for Canadian conventional oil and gas operations, excluding synthetic oil, was slightly higher in 2011 compared to 2010 as the benefit of significantly higher natural gas production at Tupper West and Tupper was more than offset by lower production volumes without a comparable reduction in costs at Hibernia and Terra Nova. Higher cost per barrel in 2011 compared to 2010 at Canadian synthetic oil operations was mostly caused by higher overall maintenance and fuel costs. Production cost per unit in Malaysia was higher in 2011 compared to 2010, with the increase primarily at Kikeh caused by higher costs for the work program to address equipment damaged by sand produced with the oil and the associated downtime which led to lower oil production. Production expense in Republic of the Congo was lower on a per-unit basis in 2011 compared to 2010 due to a reduction in gross costs incurred at the Azurite field in the later year.

35-------------------------------------------------------------------------------- Table of Contents Exploration expenses for 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-51 and F-52 on this Form 10-K report. Expenses other than leasehold amortization are included in the capital expenditures total for exploration and production activities.

(Millions of dollars) 2012 2011 2010 Dry holes $ 181.9 251.0 74.9 Geological and geophysical 32.2 79.3 64.4 Other 37.0 40.9 28.8 251.1 371.2 168.1 Undeveloped lease amortization 129.8 118.2 108.0 Total exploration expenses $ 380.9 489.4 276.1 Dry hole expense was $69.1 million lower in 2012 than in 2011 due to better drilling success coupled with lower exploratory drilling spending. Dry hole expense in 2012 in other foreign areas was significantly lower than in 2011 primarily due to unsuccessful wells drilled in the prior year in Brunei, Indonesia and Suriname. Dry hole expense in Canada was also significantly lower in 2012 due to fewer unsuccessful wells drilled in Southern Alberta in the current year. Dry hole expense in the U.S. was higher in 2012 mostly due to a decision by the owners in 2012 not to develop a well drilled in a prior year in the deepwater Gulf of Mexico; the well was expensed in 2012. Malaysian operations had higher dry hole expense in 2012 due to an unsuccessful well drilled in Block P and expensing of two wells drilled in a prior year offshore Sarawak caused by government denial of a request for extension of an oil field development plan deadline. Dry hole expense in Republic of the Congo was higher in 2012 than 2011 due to expensing two wildcat wells following unsuccessful drilling in the MPN block in the later year. Geological and geophysical (G&G) expenses were $47.1 million lower in 2012 than 2011. Areas with lower spending on seismic in 2012 included the Gulf of Mexico, Brunei, the Kurdistan region of Iraq, and Block H Malaysia. Other exploration costs in 2012 were $3.9 million below 2011 levels primarily due to lower lease rentals on undeveloped acreage in Western Canada in the current year. Undeveloped leasehold amortization expense rose $11.6 million in 2012 compared to 2011, primarily due to higher amortization associated with Eagle Ford Shale area leases.

Dry hole expense was $176.1 million higher in 2011 than 2010 due to more unsuccessful exploratory drilling results in 2011, with the most significant areas including Brunei, Indonesia, Southern Alberta and Suriname. Lower dry hole costs in 2011 in Malaysia and Republic of the Congo somewhat offset these higher costs. G&G expenses were $14.9 million higher in 2011 compared to 2010. The increase in G&G expenses in 2011 was attributable to higher spending on seismic in Brunei, the Kurdistan region of Iraq, Block H Malaysia and Cameroon, but 2011 included lower seismic spending in Republic of the Congo. Other exploration costs were $12.1 million more in 2011 than 2010 mostly due to higher office costs for exploration activities in Brunei, Indonesia and Kurdistan region of Iraq, and an exploration well drilling penalty in Southern Alberta. Undeveloped leasehold amortization expense was $10.2 million higher in 2011 than 2010 mostly due to lease costs associated with concessions in the Kurdistan region of Iraq, but partially offset by slightly lower amortization costs in 2011 for both Eagle Ford Shale leases in South Texas and the Montney area leases in Western Canada.

The Company's E&P operations recorded an impairment charge of $200.0 million in 2012 for oil production operations at the Azurite field, offshore Republic of the Congo, compared to an impairment charge of $368.6 million for Azurite in 2011. The current year charge was required due to the removal of all proved reserves at year-end 2012 following the Company's decision to cease redrilling operations on a well that went off production during the year. The reserves associated with the remaining producing wells were insufficient to allow for booking as proved reserves due to uneconomic results. The 2011 impairment charge to reduce the carrying value of Azurite to fair value was necessitated by a reduction in the field's proved oil reserves at year-end 2011 due to poor performance for certain wells.

36-------------------------------------------------------------------------------- Table of Contents Depreciation, depletion and amortization expense for continuing exploration and production operations totaled $1,244.4 million in 2012, $956.0 million in 2011 and $982.6 million in 2010. The $288.4 million increase in 2012 compared to 2011 was primarily caused by higher overall volumes of oil and natural gas sold during the current year. Additionally, the average per-unit depreciation rate increased in 2012, primarily due to a higher mix of production from the Eagle Ford Shale and a higher unit rate at Kikeh due to development drilling activities at the field. The $26.6 million decrease in 2011 compared to 2010 was primarily attributable to lower overall levels of hydrocarbon volumes sold, somewhat offset by a slightly higher per-barrel depreciation rate based on a change in the mix of production between 2011 and 2010.

The exploration and production business recorded expenses of $38.4 million in 2012, $33.8 million in 2011 and $28.8 million in 2010 for accretion on discounted abandonment liabilities. Because the liability for future abandonment of wells and other facilities 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 $4.6 million increase in accretion expense in 2012 compared to 2011 was due to additional wells drilled during the later year in Malaysia and higher estimated abandonment costs for wells in the Gulf of Mexico and for synthetic oil operations at Syncrude. The $5.0 million increase in accretion costs in 2011 compared to 2010 was attributable to a higher number of wells drilled in 2011 in the Eagle Ford Shale and Montney areas and higher overall future estimated abandonment cost liabilities for Gulf of Mexico wells and synthetic oil operations at Syncrude.

The effective income tax rate for exploration and production continuing operations was 40.1% in 2012, 52.6% in 2011 and 41.2% in 2010. The overall effective income tax rate was significantly lower in 2012 than 2011 mostly due to tax benefits of $108.3 million recorded in 2012 associated with exploration activities in Republic of the Congo and Suriname. Additionally, 2012 had lower exploration expenses in foreign jurisdictions where no tax benefit is available at the present time due to lack of available revenue needed to realize a current or future benefit. The effective tax rate was significantly higher in 2011 than 2010 due to no tax benefit recorded on the $368.6 million impairment charge for the Azurite field and higher exploration and administrative expenses in certain foreign tax jurisdictions where no tax benefit can be currently recognized due to lack of sufficient revenue to realize a current or future benefit. Income tax expense in 2011 was reduced by a $25.6 million benefit for expenses incurred in prior years in Block P, Malaysia. It was determined during 2011 that Block P expenses are deductible against taxable income generated in Block K Malaysia.

The effective tax rates in all three years exceeded the U.S. statutory tax rate of 35.0% due to higher overall foreign tax rates and exploration and other expenses in areas where current tax benefits cannot be recorded by the Company.

Tax jurisdictions with no current tax benefit on expenses primarily include certain non-revenue generating areas in Malaysia as well as Suriname, Australia, Indonesia, Brunei, Cameroon and the Kurdistan region of Iraq. 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 Block H, offshore Sabah, and Blocks PM 311/312, offshore Peninsular Malaysia.

At December 31, 2012, 94.6 million barrels of the Company's U.S. proved oil reserves and 130.9 billion cubic feet of U.S. proved natural gas reserves were undeveloped. Approximately 82% of the total U.S. undeveloped reserves (on a barrel of oil equivalent basis) are associated with the Company's Eagle Ford Shale operations in South Texas. Further drilling and facility construction are generally required to move the undeveloped reserves in the Eagle Ford Shale area to developed. In the Western Canadian Sedimentary Basin, total proved undeveloped natural gas reserves totaled 134.6 billion cubic feet, with the migration of these reserves, primarily in the Tupper and Tupper West areas, dependent on both development drilling and completion of processing and transportation facilities. In Block K Malaysia, oil reserves of 12.6 million barrels for the Kakap field are undeveloped pending completion of the main facilities and additional development drilling directed by another company.

Additionally, the Kikeh field had undeveloped oil reserves of 8.0 million barrels, which are subject to further drilling before being moved to developed.

Also in Malaysia, there were 145.9 billion cubic feet of undeveloped natural gas reserves at various fields offshore Sarawak at year-end 2012, which were held under the undeveloped category pending completion of development drilling and facilities. The deepwaters of the Gulf of Mexico and the Schiehallion field in the U.K. North Sea accounted for additional proved undeveloped reserves of 20.6 million and 17.4 million equivalent barrels of oil, respectively, at December 31, 2012. On a worldwide basis, the Company spent approximately $3.30 billion in 2012, $1.88 billion in 2011 and $1.27 billion in 2010 to develop proved reserves.

37 -------------------------------------------------------------------------------- Table of Contents Refining and Marketing - The Company's refining and marketing (R&M) operations generated earnings from continuing operations of $157.6 million in 2012, $190.3 million in 2011 and $130.6 million in 2010. The R&M earnings reduction of $32.7 million in 2012 compared to 2011 was driven primarily by a weaker U.S.

retail marketing sales margin of $0.027 per gallon, and lower earnings and an impairment charge for U.S. ethanol production operations. These unfavorable results in the U.S. were partially offset by improved refining and marketing margins in the U.K. in 2012 compared to the prior year. The R&M earnings improvement of $59.7 million in 2011 compared to 2010 was mostly attributable to a $0.042 per gallon improvement in retail fuel marketing sales margin in the U.S. and higher profits on merchandise sales at U.S. retail stations in 2011.

The Company has announced its intention to separate its U.S. downstream business into a separate publicly owned company as well as its intention to divest its U.K. refining and marketing operations. The Meraux, Louisiana and Superior, Wisconsin refineries were sold in 2011 and have been reported as discontinued operations for all periods presented.

The Company's United States R&M operations generated earnings from continuing operations of $105.4 million in 2012, down from $223.6 million in 2011 and $165.3 million in 2010. U.S. R&M operations include retail and wholesale fuel marketing operations, along with two ethanol production facilities. U.S. R&M profits decreased $118.2 million in 2012 compared to 2011. Margins for retail fuel marketing operations declined from $0.156 per gallon in 2011 to $0.129 per gallon in 2012. The margin decline in the current year was primarily attributable to generally rising wholesale gasoline prices which were not fully recovered from customers at the pump. Fuel volumes sold by the retail marketing business in 2012 on a per store basis were lower than the prior year by 0.3%.

Also, the U.S. retail business was adversely affected in 2012 by higher allocated administrative expense. The U.S. retail operating results benefited from stronger profits on merchandise sales in 2012 as margins as a percent of sales improved by 5% in the current year. U.S. ethanol production operations experienced significantly weaker margins in 2012 compared to 2011. Based on these squeezed margins and an expectation of weak results in future periods, the Company recorded an after-tax impairment charge of $39.6 million in 2012 to write down the carrying value of its Hereford, Texas ethanol production facility.

The $58.3 million increase in U.S. income from continuing operations in 2011 compared to 2010 was primarily attributable to more than a $0.04 per gallon improvement in retail fuel margin partially offset by a reduction in gallons sold. Additionally, the Company had higher profits in 2011 on the sale of merchandise in this business. Total fuel sales volumes per station at Company operated sites in the U.S. averaged about 277,700 gallons per month during 2011, down 9% from 2010. U.S. profits in 2011 included higher income from the Company's ethanol production facilities compared to 2010. The Hankinson plant operated for both years while the Hereford plant was open for most of 2011 only.

Corn costs were higher in 2011 compared to 2010, but this increase was essentially offset by higher sales prices for ethanol and by-products, dried distillers grains and wet distillers grains, in the later year.

United States refined product sales volumes (including discontinued operations) averaged 337,900 barrels per day in 2012, compared to 420,737 barrels per day in 2011 and 450,100 barrels per day in 2010. The decreases in 2012 and 2011 versus each prior year were primarily due to the sale of the two U.S. refineries near the end of September 2011. Sales volume in 2011 included nine months of finished products made prior to the sale of the refineries near the end of September 2011. A full year of ethanol production in 2012 from the Hereford facility, which commenced operation in early 2011, partially offset the reduced sales volume due to the sale of the refineries in 2011. The retail marketing business added 37 stations in 2012, 29 stations in 2011 and 51 stations in 2010. The U.S.

retail marketing network included 1,165 stations at year-end 2012. As previously announced, the Company entered into an agreement with Wal-Mart Stores near year-end 2012 that will allow the Company to obtain sites to build additional fueling stations at more than 200 Walmart supercenter stores. These store additions are expected to be phased in over approximately the next three years.

38 -------------------------------------------------------------------------------- Table of Contents United Kingdom R&M operations generated a profit of $52.2 million in 2012 compared to losses of $33.3 million in 2011 and $34.7 million in 2010. Results in 2012 were $85.5 million better than 2011 for U.K. R&M operations primarily due to much stronger margins at the Milford Haven, Wales, refinery in the latest year. During the two-year period of 2011 and 2010, U.K. refining margins were hurt by weak demand, leading to an oversupply of motor fuel products in the U.K.

and Western Europe. Additionally, in 2012 the U.K. marketing operations generated stronger margins on sale of fuel products compared to 2011. In 2011, operating results for U.K. R&M operations improved by $1.4 million compared to 2010, primarily caused by slightly better refining margins and higher throughput volumes in 2011 due to a two-month plant wide turnaround at the Milford Haven refinery in 2010.

Unit margins in the United Kingdom averaged $1.94 per barrel in 2012, $(0.67) per barrel in 2011 and $(1.47) per barrel in 2010. Overall refined product sales volumes in the U.K. averaged 137,049 barrels per day in 2012, up 1% compared to 2011. Sales volumes of refined products in the U.K. increased 57% in 2011 compared to 2010 and averaged 135,697 barrels per day. The significant volume increase in 2011 was essentially due to downtime for a refinery turnaround in 2010.

Corporate - The after-tax costs of corporate activities, which include interest income, interest expense, foreign exchange gains and losses, and unallocated corporate overhead, were $98.5 million in 2012, $75.0 million in 2011 and $157.9 million in 2010.

The net cost of corporate activities rose $23.5 million in 2012 compared to 2011. The most significant variance related to the effects of foreign currency exchange, which were associated with transactions denominated in currencies other than the respective operation's predominant functional currency. While 2011 benefited from after-tax gains of $20.7 million from foreign currency exchange, the foreign currency effects in 2012 were minimal. During 2012, the after-tax impact of foreign exchange losses for Malaysian operations was essentially offset by after-tax foreign exchange benefits in the U.K. Interest income was $3.6 million less in 2012 compared to the prior year, with the variance primarily related to interest earned in 2011 on a U.S. Federal royalty refund. Administrative expenses for corporate activities were up $18.8 million in 2012 compared to 2011 due to both higher employee compensation and higher professional services costs. The increase in professional services was primarily associated with both the anticipated separation of the U.S. R&M business and the intended sale of the U.K. R&M business. Net interest expense, after capitalization of finance-related costs to development projects, was $25.8 million lower in 2012 than 2011 mostly due to larger amounts of interest capitalized on oil development projects during the just completed year. Income taxes associated with corporate activities in 2012 were unfavorable to 2011 primarily due to pretax variances from foreign currency exchange effects.

The net cost of corporate activities in 2011 was $82.9 million lower than in 2010, primarily due to more favorable effects of foreign currency exchange. The effect of foreign currency exchange after taxes was a gain of $20.7 million in 2011 compared to a loss after taxes of $58.1 million in 2010. The U.S. dollar generally strengthened against the Malaysian ringgit in 2011 after having weakened against this currency during 2010. The stronger U.S. currency in 2011 reduced the dollar cost of tax liabilities in Malaysia which are payable in the local currency. The Malaysian operation's functional currency is the U.S.

dollar. Foreign currency transaction effects in the U.K. were also favorable in 2011 compared to 2010. The corporate area also benefited in 2011 from higher interest income of $3.2 million compared to 2010, principally due to interest received in 2011 on a U.S. Federal royalty refund. Net interest expense, after capitalization of finance-related costs to development projects, was $6.0 million higher in 2011 than 2010. This unfavorable variance was principally due to interest charged on certain tax assessments in Canada and lower amounts of interest capitalized to development projects in 2011, primarily at the Tupper West area development in Western Canada where gas production started up in the first quarter of 2011. Administrative expenses associated with corporate activities were also higher in 2011 compared to 2010, primarily associated with additional costs for employee compensation and professional services.

Discontinued Operations - On September 30, 2011, the Company sold its Superior, Wisconsin refinery and related assets for $214 million, plus certain capital expenditures between July 25, 2011 and the date of closing 39-------------------------------------------------------------------------------- Table of Contents and the fair value of all associated hydrocarbon inventories at these locations.

On October 1, 2011, the Company sold its Meraux, Louisiana refinery and related assets for $325 million, plus the fair value of associated hydrocarbon inventories. The Company has accounted for the Superior, Wisconsin and Meraux, Louisiana refineries and associated marketing assets as discontinued operations in all periods presented.

The Company also entered into contracts in late 2012 to sell its U.K. oil and gas operations. The sales are expected to be completed in the first quarter of 2013. The results of the U.K. oil and gas operations for all periods have been presented as discontinued operations in the Consolidated Statements of Income.

The assets and liabilities related to these operations to be sold have been reported as held for sale in the December 31, 2012 Consolidated Balance Sheet.

Income from discontinued operations totaled $6.8 million in 2012, $143.2 million in 2011 and $49.0 million in 2010. Income from discontinued operations in 2012 included profitable results of U.K. oil and gas operations, which were partially offset by net costs for tax adjustments and other matters related to U.S.

refineries sold in 2011. The primary reason for the $136.4 million decline in 2012 income from discontinued operations compared to the prior year was a sizable operating profit of $113.1 million in the first nine months of 2011 for the two U.S. refineries sold. Results in 2011 also included an after-tax gain on disposal of the refineries of $18.7 million. In July 2012, the United Kingdom enacted tax changes that limited tax relief on oil and gas decommissioning costs to 50%, a reduction from the 62% tax relief previously allowed for these costs.

This tax rate change led to a net reduction of income from discontinued operations of $5.5 million in 2012. The prior year results included a larger unfavorable effect from tax rate changes in the U.K., which is further described in the following paragraph.

Income from discontinued operations was $143.2 million in 2011. This 2011 income included U.S. refinery operating profits of $113.1 million, an after-tax gain on sale of the two U.S. refineries of $18.7 million, and operating profits of $11.5 million from U.K. oil and gas operations. U.S. refinery operating profits in 2011 of $113.1 million were significantly better than the 2010 operating profits of $18.5 million due to much stronger refining margins in 2011. The after-tax gain from disposal of the two refineries included a gain on sale of the Superior refinery and associated inventories of $77.6 million and a loss on sale of the Meraux refinery and associated inventories of $58.9 million. The net gain on disposal was based on the selling prices of the refineries, plus the sales of all associated inventories. These inventories were sold at fair value, which was significantly above the last-in, first-out carrying value of these assets. In 2011, the U.K. government enacted a 12% supplemental tax on oil and gas company profits in that country. This tax increase reduced income from discontinued operations in 2011 by $14.5 million, primarily to increase the recorded balance for deferred income taxes that will be paid in future years at the new higher rate. The rate change increased the effective tax rate to 62% in the U.K.

Capital Expenditures As shown in the selected financial data on page 26 of this Form 10-K report, capital expenditures from continuing operations, including exploration expenditures, were $4.33 billion in 2012, compared to $2.88 billion in 2011 and $2.32 billion in 2010. These amounts excluded capital expenditures of $57.2 million in 2012, $68.3 million in 2011 and $128.8 million in 2010 related to discontinued operations, which were associated with two U.S. petroleum refineries sold during 2011 and U.K. oil and gas assets expected to be sold in early 2013. Capital expenditures included $251.1 million, $371.2 million and $168.1 million, respectively, in 2012, 2011 and 2010 for exploration costs that were expensed.

Capital expenditures for exploration and production continuing operations totaled $4.19 billion in 2012, $2.75 billion in 2011 and $2.02 billion in 2010, representing 97%, 96% and 87%, respectively, of the Company's total capital expenditures from continuing operations for these years. E&P capital expenditures in 2012 included $132.5 million for acquisition of undeveloped leases, which primarily included leases acquired in the Gulf of Mexico, the Eagle Ford Shale area of South Texas and in Northwest Alberta, Canada, $450.6 million for exploration activities, $3.29 billion for development projects and $311.5 million for acquisition of proved properties in Canada and the Gulf of Mexico. Exploration activities primarily included exploratory drilling in the 40 -------------------------------------------------------------------------------- Table of Contents United States, Southern Alberta in Canada, Block H in Malaysia, Republic of the Congo, the Kurdistan region of Iraq and Brunei. Other primary exploration activities were associated with geophysical data acquisitions in the U.S. and various foreign countries. Development expenditures included $1.11 billion in the Eagle Ford Shale; $157.3 million at the Tupper and Tupper West areas; $200.1 million for deepwater fields in the Gulf of Mexico; $627.8 million for Kikeh; $558.6 million for oil and natural gas development activities in SK Blocks 309/311; $107.0 million and $83.9 million for the Kakap and Siakap developments, respectively, in Block K, Malaysia; $125.1 million for Syncrude; $222.4 million for Western Canada heavy oil projects; and $73.1 million for the Terra Nova and Hibernia oil fields, offshore Newfoundland.

Capital expenditures in 2011 from E&P continuing operations included $279.3 million for undeveloped lease acquisitions, $23.5 million associated with a contract revision at the Azurite field, $559.7 million of exploration activities and $1.89 billion for development programs. Lease acquisitions were primarily associated with activities in the Eagle Ford Shale area of South Texas and exploration concessions in the Kurdistan region of Iraq. Exploration costs principally related to exploratory drilling at resource plays in North America, including the Eagle Ford Shale in South Texas and new areas in Southern Alberta, plus wildcat drilling activities in Brunei, Indonesia and Suriname. Development projects in 2011 primarily included spend of $572.2 million at the Tupper West and Tupper natural gas areas in Western Canada; $153.7 million for Seal heavy oil area activities; $339.6 million for the Kikeh field in Malaysia; $236.4 million for Sarawak SK Blocks 309/311 oil and gas projects offshore Malaysia; $115.7 million for the Kakap field in Block K, offshore Sabah Malaysia; $219.7 million for work in the Eagle Ford Shale; and $73.9 million for synthetic oil operations at Syncrude. Exploration and production capital expenditures are shown by major operating area on page F-50 of this Form 10-K report.

Refining and marketing capital expenditures for continuing operations totaled $133.7 million in 2012, $122.3 million in 2011 and $290.1 million in 2010. These amounts represented 3%, 4% and 13% of capital expenditures of the Company in 2012, 2011 and 2010, respectively. Total refining and marketing capital expenditures above excluded $48.1 million and $117.3 million in 2011 and 2010, respectively, for U.S. refineries sold in 2011, which are classified as discontinued operations. Marketing expenditures amounted to $110.7 million in 2012, $84.9 million in 2011 and $185.4 million in 2010. Marketing capital spending in all three years was principally related to new station construction in the U.S. market. The Company added 37 stations within its U.S. retail gasoline network in 2012, after adding 29 in 2011 and 51 in 2010. Refining capital spend within continuing operations totaled $14.5 million in 2012, $14.7 million in 2011 and $59.8 million in 2010. These expenditures related to the Milford Haven, Wales refinery, and in 2012 and 2011 principally included minor capital improvements, while the majority of 2010 spend related to costs to complete expansion of the crude oil throughput capacity at Milford Haven to 135,000 barrels per day. Refining capital spending for discontinued operations during 2011 and 2010 primarily included costs at Meraux to reduce benzene production and construct a new laboratory, and at Superior to meet compliance with ultra-low sulfur diesel and Mobile Source Air Toxic requirements. Capital expenditures related to ethanol operations in the U.S. totaled $8.5 million in 2012, $22.7 million in 2011 and $44.9 million in 2010. The Company spent $40.0 million in 2010 to acquire an unfinished ethanol production facility in Hereford, Texas. Construction of the Hereford facility was completed at an added cost of about $25.1 million and the facility commenced operation near the end of the first quarter 2011.

Cash Flows Operating activities- Cash provided by operating activities was $3.06 billion in 2012, $2.15 billion in 2011 and $3.13 billion in 2010. Cash flows associated with formerly owned U.S. refineries and the held for sale U.K. oil and gas production business have been classified as discontinued operations in the Company's consolidated financial statements. Cash provided by operating activities included cash from these discontinued operations of $61.1 million in 2012, $185.5 million in 2011 and $159.5 million in 2010. Cash provided by continuing operations in 2012 was $1.04 billion more than 2011 primarily due to a lower use of cash to build working capital other than cash, higher income from continuing operations in the current year, and higher non-cash expenses for depreciation and deferred taxes in 2012. Cash provided by continuing operations in 2011 was 41 -------------------------------------------------------------------------------- Table of Contents $1.01 billion less than 2010 primarily due to timing of cash collected and disbursed associated with changes in other working capital balances. Cash was primarily used in 2011 to pay down accounts payable for crude oil feedstocks at formerly owned U.S. petroleum refineries and to pay income taxes in the U.S. and Malaysia. Cash flow from continuing operations in 2010 included cash receipts of $286.4 million related to recovery of U.S. Federal royalties and associated interest income. The income associated with the royalty recovery was recorded in 2009, but the cash proceeds were collected in early 2010. Cash provided by operating activities was reduced by expenditures for abandonment of oil and gas properties totaling $40.4 million in 2012, $21.5 million in 2011 and $36.5 million in 2010. Operating cash flows were reduced by payments of income taxes of $567.0 million in 2012, $938.9 million in 2011 and $585.8 million in 2010. The total reductions of operating cash flows for interest paid during the three years ended December 31, 2012, 2011 and 2010 were $48.7 million, $53.3 million and $53.9 million, respectively.

Investing activities - Cash proceeds from property sales classified as continuing operations were $0.6 million in 2012, $27.8 million in 2011 and $2.2 million in 2010. The 2011 proceeds primarily related to sale of gas storage assets in Spain. In 2011, the Company generated cash of $950.0 million from sale of two U.S. refineries and associated marketing assets, including liquid inventories. Other investing activities for discontinued operations included cash payments for capital expenditures of $58.2 million in 2012, $68.4 million in 2011 and $127.9 million in 2010. Additionally, the two U.S. refineries which were sold used cash of $1.5 million in 2011 and $37.5 million in 2010 for maintenance turnarounds. Property additions and dry hole costs for continuing operations used cash of $3.67 billion in 2012, $2.60 billion in 2011 and $2.19 billion in 2010. Cash used to pay for capital expenditures increased each year compared to the prior year, with these variances essentially in line with changes in capital expenditures in each year. Cash of $1.62 billion, $1.69 billion and $2.39 billion was spent in 2012, 2011 and 2010, respectively, to acquire Canadian government securities with maturities greater than 90 days at the time of purchase. Proceeds from maturities of Canadian government securities with maturities greater than 90 days at date of acquisition were $2.04 billion in 2012, $1.77 billion in 2011 and $2.55 billion in 2010. Cash of $12.8 million in 2012, $5.4 million in 2011 and $61.4 million in 2010 was used for turnarounds at the Milford Haven refinery, at Syncrude and at U.S. ethanol plants. The high spend in 2010 was attributable to a plant-wide turnaround at Milford Haven.

Financing activities - During 2012, the Company sold $2.0 billion of long-term notes. The proceeds of these notes were primarily used to repay $350.0 million of notes that matured in 2012, to repay other debt, to fund a special dividend totaling $486.1 million, to fund $250.0 million of an announced stock buyback program of up to $1.0 billion, and to fund a portion of the Company's development capital expenditures. Through December 31, 2012, the Company had paid $250.0 million to acquire 3.87 million of its Common shares under an accelerated stock repurchase program (ASR) with a major financial institution.

Additional shares may be delivered to the Company upon completion of the ASR in 2013. During 2011 and 2010, the Company used available cash flow to repay $340.0 million and $414.0 million, respectively, of debt. The debt reduction in 2011 was accomplished with proceeds from sale of the two U.S. refineries. The 2010 debt reduction included a full repayment of the nonrecourse loan used to partially finance the acquisition of the Hankinson, North Dakota ethanol plant.

Cash proceeds from stock option exercises and employee stock purchase plans, including income tax benefits on stock options, amounted to $15.0 million in 2012, $20.4 million in 2011 and $54.7 million in 2010. In 2012, the Company paid $7.0 million of fees associated with sales of the $2.0 billion of long-term notes. In 2011, the Company used cash of $7.9 million for fees and other expenses associated with renewing its primary $1.5 billion committed credit facility that expires in June 2016. In 2012, 2011 and 2010, cash of $3.3 million, $8.0 million and $5.2 million, respectively, was used to pay statutory withholding taxes on stock-based incentive awards that vested with a net-of-tax payout. Cash used for dividends to stockholders was $714.4 million in 2012, $212.8 million in 2011 and $201.4 million in 2010. The Company increased its normal dividend rate by 14% in 2012 as the annualized dividend was raised from $1.10 per share to $1.25 per share effective in the third quarter 2012. The Company had previously raised its annualized dividend rate from $1.00 per share to $1.10 per share beginning in the third quarter of 2010. Additionally, in December 2012, the Company paid a special dividend of $2.50 per share.

42-------------------------------------------------------------------------------- Table of Contents Financial Condition Year-end working capital (total current assets less total current liabilities) amounted to $699.5 million in 2012 and $622.7 million in 2011. 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 $571.2 million below fair value at December 31, 2012. Cash and cash equivalents at the end of 2012 totaled $947.3 million compared to $513.9 million at year-end 2011. In addition, the Company had short-term investments in Canadian government treasury securities of $115.6 million at year-end 2012. These short-term investments could quickly be converted to cash if a need for funds in Canada arose.

Long-term debt increased by $1,995.6 million in 2012. A portion of the increase in long-term debt in 2012 was associated with issuance of $500.0 million of long-term notes in May 2012. The proceeds from these notes were used to repay $350.0 million of notes that matured in May 2012 and which were classified as a current liability at December 31, 2011. In late 2012, the Company sold $1.5 billion of long-term notes in the market. Part of the proceeds of these notes were used to pay a $2.50 per share special dividend that totaled $486.1 million and to fund a $250.0 million stock buyback through an accelerated stock repurchase plan with a major financial institution. The remainder of the note proceeds were used to repay debt that was then outstanding under the Company's committed credit facility and to fund capital expenditures. At December 31, 2012, long-term debt was 20.1% of total capital employed. During 2011, long-term debt decreased by $689.8 million and totaled $249.6 million at year-end 2011, representing 2.8% of total capital employed. The reduction in long-term debt in 2011 included a $350.0 million reclassification of notes payable due in 2012 to a current liability. Stockholders' equity was $8.94 billion at the end of 2012 compared to $8.78 billion at the end of 2011 and $8.20 billion at the end of 2010. A summary of transactions in stockholders' equity accounts is presented on page F-8 of this Form 10-K report.

Other changes in Murphy's year-end 2012 balance sheet compared to 2011 included a $416.5 million reduction in the balance of short-term investments in Canadian government securities with maturities greater than 90 days at the time of purchase. The total investment in these Canadian government securities was $115.6 million at year-end 2012 and $532.1 million at year-end 2011. These short-term investments were reduced in late 2012, with the proceeds partially used to fund a purchase of Seal heavy oil field properties in Western Canada.

The remainder of the investment proceeds was used to fund other capital investments in Canada and for an intercompany loan to the U.K. business which was repaid in early 2013. These slightly longer-term Canadian investments were purchased in each year because of a tight supply of shorter-term securities available for purchase in Canada. A $299.2 million increase in accounts receivable in 2012 was primarily caused by higher sales prices for crude oil and finished products, and higher natural gas sales volumes sold on credit terms by the Company. Inventory values were $85.7 million more at year-end 2012 than in 2011 mostly due to larger levels of crude oil held in storage within U.K.

downstream operations, plus more drilling equipment inventory held within the E&P business in the later year. Prepaid expenses increased $242.4 million in 2012 primarily due to prepaid income taxes in the U.S. and Canada, plus higher levels of prepaid insurance costs at year-end 2012. Short-term deferred income tax assets were $1.6 million higher at year-end 2012 compared to 2011. Current assets held for sale of $15.1 million at December 31, 2012 primarily represent accounts receivable and crude oil and other inventory costs associated with U.K.

oil and gas producing assets to be sold in early 2013. Net property, plant and equipment increased by $2.54 billion in 2012 as the level of property additions during the year exceeded the amounts of depreciation, amortization and impairment expenses recorded during the year. Goodwill increased $1.2 million in 2012 due to a stronger Canadian dollar exchange rate versus the U.S. dollar.

Deferred charges and other assets decreased $22.3 million due to amortization of deferred turnaround costs associated with the Milford Haven refinery and transfer to Property, Plant and Equipment of long-lead equipment that was placed in service. These were somewhat offset by higher deferred financing costs associated with sale of $2.0 billion of notes during 2012. Assets held for sale-noncurrent of $208.2 million at year-end 2012 represents primarily property and equipment associated with U.K. oil and gas producing assets to be sold in early 2013. Current maturities of long-term debt at year-end 2012 was $350.0 million lower than at the prior year-end due to repayment of $350.0 million of notes payable that matured during 2012 and replacement of these notes with $500.0 million of 10-year 43 -------------------------------------------------------------------------------- Table of Contents notes that mature in 2022 and which have been classified as long-term debt at December 31, 2012. Accounts payable increased by $862.3 million at year-end 2012 compared to 2011 primarily due to higher capital and operating expenses owed to vendors in the U.S., Malaysia and Republic of the Congo at year-end 2012, partially offset by lower amounts owed for purchased crude oil feedstocks at the Milford Haven refinery in 2012. Income taxes payable was $18.1 million higher at year-end 2012 than at the end of 2011, primarily due to higher levels of taxes owed in 2012 for Malaysian operations. Other taxes payable at year-end 2012 was $3.4 million higher than in 2011 mostly due to higher excise taxes owed by U.S.

downstream operations, partially offset by lower withholding taxes owed by Canadian operations. Other accrued liabilities increased by $22.9 million at year-end 2012 mostly due to higher amounts owed for compensation, retirement and asset dismantlement and reclamation costs. The current portion of deferred income tax liabilities decreased $20.0 million in 2012 due to lower short-term temporary differences for tax deductions in Canada in the current year.

Liabilities associated with assets held for sale-current of $47.5 million at December 31, 2012 primarily represent U.K. oil and gas operations payables to vendors and tax authorities. Noncurrent deferred income tax liabilities were $314.2 million higher at year-end 2012 mostly due to accelerated tax depreciation associated with the Company's 2012 capital expenditures, primarily in the U.S., Canada and Malaysia. The liability associated with future asset retirement obligations increased by $108.7 million at year-end 2012 mostly due to higher estimated future costs to abandon oil and gas properties in the U.S., Canada and Malaysia. Deferred credits and other liabilities were $76.9 million more in 2012 compared to 2011 primarily due to higher noncurrent retirement plan liabilities and other long-term obligations at year-end 2012. Liabilities associated with assets held for sale-noncurrent of $141.2 million primarily represents abandonment and deferred tax obligations associated with U.K. oil and gas assets to be sold in early 2013. Total stockholders' equity of the Company increased by $163.6 million in 2012. The components of this increase in stockholders' equity are reflected in the Consolidated Statement of Stockholders' Equity on page F-8 of the consolidated financial statements.

Murphy had commitments for future capital projects of approximately $2.42 billion at December 31, 2012, including $977.8 million for field development and future work commitments in Malaysia, $242.0 million for costs to develop deepwater Gulf of Mexico fields, $474.1 million for work in the Eagle Ford Shale, and $146.8 million and $124.1 million for future work commitments offshore Brunei and Cameroon, respectively.

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, 2012, the Company had access to a long-term committed credit facility in the amount of $1.5 billion.

There were no outstanding borrowings under the committed credit facility at year-end 2012. 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%. The committed credit facility expires in June 2016. At December 31, 2012, the Company had uncommitted bank credit lines of approximately $320.0 million, but no borrowings were outstanding under these lines. The Company's ratio of long-term debt to total capital was 20.1% at year-end 2012. In October 2012, the Company filed a Form S-3 registration statement with the U.S. Securities and Exchange Commission which permits the offer and sale of debt and/or equity securities. The Company used this shelf registration and a former one in 2012 to sell long-term notes totaling $2.0 billion. The current shelf registration will expire in October 2015.

Current financing arrangements are set forth more fully in Note E to the consolidated financial statements. Based on the anticipated level of capital expenditures the Company has budgeted during 2013, the Company anticipates that it will need to borrow under its long-term credit facility during 2013. The Company's ratio of earnings to fixed charges was 16.6 to 1 in 2012, 15.1 to 1 in 2011 and 14.0 to 1 in 2010.

Cash and invested cash are maintained in several operating locations outside the United States. At December 31, 2012, cash, cash equivalents and cash temporarily invested in Canadian government securities held outside the U.S. included $184.2 million in Canada, $580.2 million in Malaysia and $78.0 million in the U.K. In certain cases, the Company could incur taxes or other costs should these cash balances be repatriated to the U.S. in future periods. This could occur due to withholding taxes and/or potential additional U.S. tax burden when less 44-------------------------------------------------------------------------------- Table of Contents than the U.S. tax rate of 35% has been paid for cash taxes in foreign locations.

A lower cash tax rate is often paid in the U.S. and foreign countries in the early years of operations when accelerated tax deductions exist to incent oil and gas investments; cash tax rates are generally higher in later years after accelerated tax deductions in early years are exhausted. Canada collects a 5% withholding tax on any cash repatriated to the U.S. See Note H of the consolidated financial statements for further information regarding potential tax expense that could be incurred upon distribution of foreign earnings back to the United States.

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. Virtually all operations of the Company are affected by laws and regulations covering environmental, health and safety matters. Compliance with existing and anticipated environmental regulations affects Murphy's overall cost of business, including capital costs to construct, maintain and upgrade equipment and facilities, and operating costs for ongoing environmental compliance. Murphy's competitive position may be impacted to the extent that regulatory requirements with respect to a particular production technology may give rise to costs that competitors might not bear. Environmental regulations have historically been subject to frequent change by regulatory authorities and these are expected to continue to evolve in the foreseeable future. The Company is unable to predict the ongoing cost of complying with these laws and regulations or the future impact of such regulations on its 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 Murphy 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.

Murphy allocates a portion of its capital expenditure program to comply with environmental laws and regulations, and such capital expenditures were $81.8 million in 2012 and are projected to be $86.9 million in 2013.

The most significant of those laws and the corresponding regulations affecting Murphy's operations are: • The U.S. Clean Air Act, which regulates air emissions, including greenhouse gas 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 solid waste and hazardous waste treatment, storage and disposal.

• 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 injection wells • The Federal Water Pollution Control Act of 1972 (FWPCA) also addressing discharge of pollutants into navigable waters • The Department of the Interior governing offshore oil and gas operations.

• The European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (REACH) • The European Union Trading Directive resulting in European Emissions Trading Scheme 45 -------------------------------------------------------------------------------- Table of Contents 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 in the process of 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. Murphy is 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. Murphy is actively engaged in the legislative and regulatory process, both nationally and internationally, in response to climate change issues and environmental and health related matters.

Murphy's Environmental, Health, and Safety Committee, a standing committee of the Board of Directors, was created to oversee and monitor the Company's environmental, health, and safety (EHS) policies and practices. The Board has approved a worldwide environmental, health, and safety policy (the EHS Policy), which is available on the Company's Web site. In addition to requiring that the Company comply with all applicable EHS laws and regulations, the EHS Policy includes a directive that the Company will continue to minimize the impact of its operations, products and services on the environment by implementing economically feasible projects that promote energy efficiency and use natural resources effectively.

CERCLA 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 requires reporting to the National Response Center for releases to the environment of substances defined as hazardous or extremely hazardous if the released quantities exceed an EPA established reportable level. 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 ordinary operations, the Company generates waste that falls within CERCLA's definition of a "hazardous substance." Murphy may be jointly and severally liable under CERCLA for all or part of the costs required to remediate sites at which such hazardous substances have been disposed of or released into the environment.

The EPA currently considers Murphy to be a PRP at two Superfund sites. At one site, the Company has thus far been unable to ascertain any association with the superfund site; Murphy intends to request further information as to the Company's connection to the site. 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, the Company believes that it is a de minimis party as to ultimate responsibility at the Superfund sites and as such, it has not recorded a liability for remedial costs. The Company could be required to bear a pro rata share of costs attributable to nonparticipating PRPs or could be assigned additional responsibility for remediation at these sites or other Superfund sites. The Company believes that its share of the ultimate costs to remediate these Superfund sites will be immaterial and will not have a material adverse effect on net income, financial condition or liquidity in a future period.

Waste The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled.

Although the Company has 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 the Company or on or under other locations where these wastes have 46-------------------------------------------------------------------------------- Table of Contents 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 Murphy's control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws Murphy 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, Murphy is investigating the extent of any such liability and the availability of applicable defenses, including state funding for remediation, and believe costs related to these sites will not have a material adverse affect on its net income, financial condition or liquidity in a future period. Although certain environmental expenditures are likely to be recovered from other sources, no assurance can be given that future recoveries from these sources will occur. Therefore, the Company has not recorded a benefit for likely recoveries as of December 31, 2012.

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. Murphy generates non-hazardous solid wastes that are subject to the requirements of RCRA and comparable state statutes. The Company's operating sites also incur costs to handle and dispose of hazardous waste and other chemical substances. 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.

Water 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. The Company is not aware of OPA90 claims made against Murphy.

Each Murphy offshore facility in the Gulf of Mexico has in place an Emergency Evacuation Plan (EEP) and all such facilities are covered by an Oil Spill Response Plan (OSRP). In the event of an explosion, personnel would be evacuated immediately in accordance with the EEP. The appropriate OSRP would be activated if needed. In the event of an oil spill or containment event, the appropriate OSRP and Containment Plan would be executed as needed. The EEP is approved by the U.S. Coast Guard (USCG) and the OSRP and Containment Plan are approved by the Bureau of Ocean Energy Management (BOEM). The Company also has comprehensive emergency and spill response plans for offshore facilities in international waters.

Murphy's OSRP utilizes a consortium of seasoned and well equipped contract service companies to provide response equipment and personnel. One company has been contracted to provide spill containment and recovery equipment, including skimmers, boom, and vessels such as fast response boats and high volume open sea skimmer barges. This company has hired other companies to store and maintain response equipment and provide certified tanks and barges. Murphy is a founding member of Marine Preservation Association, which provides access to Marine Spill Response Corporation assets to support marine spills in the Gulf of Mexico and other offshore areas. Additionally, Murphy has an agreement with another company to provide aerial dispersant spraying services, and has further contracted with another company to utilize their equipment for oil containment should a well blowout occur.

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 47 -------------------------------------------------------------------------------- Table of Contents damages. Murphy maintains wastewater discharge permits for its facilities where required pursuant to the FWPCA and comparable state laws. Murphy has also applied for all necessary permits to discharge storm water under such laws. The Company believes that compliance with existing permits and foreseeable new permit requirements will not have a material adverse effect on net income, financial condition or liquidity in a future period.

Murphy utilizes hydraulic fracturing technology for its exploration and production activities in Canada and the U.S. Murphy is actively engaged in exploration and production in the Eagle Ford Shale play in South Texas. On January 31, 2012, the Texas Railroad Commission finalized a rule that requires oil and gas operators to publicly disclose the chemicals and amount of water used in hydraulic fracturing of wells. Murphy is in substantial compliance with this rule.

Air Murphy's U.S. operations are subject to the Federal Clean Air Act and comparable state and local statutes. The Company believes that its operations are in substantial compliance with these statutes in all states in which it operates.

Amendments to the Federal Clean Air Act enacted in 1990 required 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.

The European Union has adopted an Emissions Trading Scheme in response to the Kyoto Protocol in order to achieve reductions in greenhouse gas emissions.

Murphy's refinery at Milford Haven, Wales, currently has 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. In 2011, Murphy was notified by the Environment Agency (EA) that it failed to surrender proper emission allowances, which Murphy self-reported to the EA in 2010. The EA has recommended a civil penalty of $1.7 million for this matter. The Company has not yet paid the proposed civil penalty and is pursuing legal means regarding this matter.

Climate Change 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 a promulgated EPA regulation, Mandatory Reporting of Greenhouse Gases for numerous industrial business segments, including refineries and offshore production, which became effective December 29, 2009. These were followed by a more recent regulation requiring Mandatory Reporting of Greenhouse Gases for Petroleum and Natural Gas Systems, including onshore exploration and production facilities, which became effective December 31, 2010 and was revised December 23, 2011. During 2011, U.S. federal legislation (EPA's Greenhouse Gas Endangerment Finding, EPA's Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, Low Carbon Fuel Standards, etc.) and various state actions were proposed/finalized to develop statewide or regional programs, each of which have or could impose mandatory reductions and reporting of greenhouse gas emissions. Murphy believes it has met all of the EPA required reporting deadlines and strives to ensure accurate and consistent emissions data reporting. The impact of existing and pending climate change legislation, regulations, international treaties and accords could result in increased costs to the Company to (i) operate and maintain facilities; (ii) install new emission controls on facilities; and (iii) administer and manage any greenhouse gas emissions trading program. These actions could also impact the consumption of refined products, thereby affecting gasoline and ethanol marketing operations.

The physical impacts of climate change present potential risks for severe weather (floods, hurricanes, tornadoes, etc.) at certain of the Company's refined product terminals in the U.S. and its offshore platforms in the Gulf of Mexico. Commensurate with this risk is the possibility of indirect financial and operational impacts to the Company from disruptions to the operations of major customers or suppliers caused by severe weather. The Company has repositioned itself to take advantage of potential climate change opportunities by acquiring renewable energy sources through the acquisition of two ethanol production facilities, thereby achieving a lower 48-------------------------------------------------------------------------------- Table of Contents carbon footprint and an enhanced capability to meet governmental fuel standards.

The Company is unable to predict at this time how much the cost of compliance with any future legislation or regulation of greenhouse gas emissions, or the cost impact of natural catastrophic events resulting from climate change, if it occurs, will be in future periods.

Environmental Stewardship The Company recognizes the importance of environmental stewardship as a core component of its mission as a responsible international energy company and has implemented sufficient disclosure controls and procedures to capture and process environmental, safety and climate-change related information. As a companion to Murphy's worldwide EHS Policy, the Company's Web site also contains a statement on climate change. Not only does this statement on climate change include Murphy's goal of reducing greenhouse gas emissions on an absolute basis while growing its upstream and certain downstream operations, the information on the Company's Web site describes actions already taken to move towards that goal.

These efforts include incorporating climate change into the Company's planning processes, reducing emissions, pursuing new opportunities and engaging legislative and regulatory entities externally. In support of these efforts, worldwide greenhouse gas inventories have been conducted since 2001.

Additionally, Murphy participates in the Massachusetts Institute of Technology (MIT) Joint Program on the Science and Policy of Global Change. The initiatives cited above demonstrate the Company's commitment regarding environmental issues, which are at the forefront of today's global public policy dialogue.

Other Matters The Energy Independence and Security Act (EISA) was signed into law in December 2007. The EISA, 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. EISA greatly increases the renewable fuels obligation defined in the Renewable Fuels Standard (RFS) 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 most of its obligation.

On July 1, 2010, the RFS-2 standard came into effect requiring the blending/phase-in of ethanol, biodiesel, cellulosic and advanced renewable fuels. Murphy is meeting its obligations for RFS-2 primarily through the RINs system.

The Company is also involved in personal injury and property damage claims, allegedly caused by exposure to or by the release or disposal of materials manufactured or used in its operations. Under Murphy's accounting policies, an environmental liability is recorded when such an obligation is probable and the cost can be reasonably estimated. If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used. Recorded liabilities are reviewed routinely.

Actual cash expenditures often occur one or more years after a liability is recognized.

Safety Matters The Company is 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 Murphy's operations and that this information be provided to employees, state and local government authorities and citizens. The Company believes that its operations are in substantial compliance with OSHA requirements, including general industry standards, record-keeping requirements and monitoring of occupational exposure to regulated substances.

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 49-------------------------------------------------------------------------------- Table of Contents 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 are often 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 at times) during the last few years primarily driven by high demand for such goods and services in a strong oil price environment. As noted elsewhere, oil and natural gas prices have been extremely volatile over the last several years. Oil prices have been strong in the last few years, while North American natural gas prices have been generally weakening due to oversupply of natural gas in this market. Oil prices in the current range of $90 per barrel and above generally lead to strong demand for oil field services. The prices for oil field goods and services generally rise in periods of higher oil prices and do not usually decline as significantly when oil and gas prices retreat. Should oil prices rise further in future periods, the Company anticipates that prices for certain oil field equipment and services could rise sharply. 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 2011, the Financial Accounting Standards Board (FASB) issued an accounting standards update that simplifies the annual goodwill impairment assessment process by permitting a company to assess whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount before applying the two-step goodwill impairment test. If a company concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the company would be required to conduct the current two-step goodwill impairment test. This change was effective for goodwill impairment tests beginning in 2012. The adoption of this standard in 2012 did not have a significant effect on Murphy's consolidated financial statements.

In June 2011, the FASB issued an accounting standards update that only permits two options for presentation of Comprehensive Income. Comprehensive Income can be presented in (a) a single continuous Statement of Comprehensive Income, including total comprehensive income, the components of net income, and the components of other comprehensive income, or (b) in two separate but continuous statements for the Statement of Income and the Statement of Comprehensive Income. The new guidance was effective for the Company beginning in the first quarter of 2012. The adoption of this guidance in 2012 did not have a significant effect on the Company's consolidated financial statements.

In February 2013, FASB issued a new rule that requires additional disclosures for reclassification adjustments from Accumulated other comprehensive income (AOCI). These additional disclosures include changes in AOCI balances by component and significant items reclassified out of AOCI. These disclosures must be presented either on the face of the affected financial statement or in the notes to the financial statements. The disclosures are effective for Murphy beginning in the first quarter of 2013 and are to be provided on a prospective basis.

The United States Congress passed the Dodd-Frank Act (the Act) in 2010. As mandated by the Act, the U.S. Securities and Exchange Commission (SEC) has recently issued rules regarding annual disclosures for purchases of "conflict minerals" and payments made to the U.S. Federal and all foreign governments by extractive industries, including oil and gas companies. These two rules are described below.

• "Conflict minerals" are defined as tin, tantalum, tungsten and gold which originate from the Democratic Republic of Congo or an adjoining country. The Company is currently investigating whether its activities will require an annual "conflict minerals" filing. If applicable, the first annual report for conflict minerals must be filed by May 31, 2014 for the calendar year of 2013.

• Due to its activities as a worldwide exploration company and a producer of oil and natural gas in several countries, the Company will be required to report annual payments made to the U.S. Federal and all foreign governments.

The recent SEC rules require disclosures of (a) the type and total amount of payments made for each project associated with extraction activities, and (b) the type and total amount of payments made to each government. The types of payments covered by the rules include taxes, royalties, fees, production entitlements, bonuses and other material benefits that are part of the commonly recognized revenue stream 50 -------------------------------------------------------------------------------- Table of Contents for oil and gas companies. The annual disclosure filing must be made within 150 days of the fiscal year-end (May 30, 2014 for the 2013 filing) and will first be required for fiscal years ending after September 30, 2013. The transition rules for 2013 allow Murphy's first filing to disclose payments for the period from October 1 to December 31, 2013. The oil and gas industry has challenged in U.S. Federal court the rules set forth by the SEC. The Company cannot predict the outcome of this court challenge.

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 gas reserves - Proved oil and gas reserves are defined by the SEC as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether a deterministic method or probabilistic method is used for the estimation. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well, or through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. 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 the Company to use an unweighted average of the oil and gas prices in effect at the beginning of each month of the year for determining quantities of proved reserves. These historical prices often do not approximate the average price that the Company expects to receive for its oil and natural gas production in the future. 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 gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserves quantities.

Reserves revisions inherently lead to adjustments of the Company's depreciation rates and the timing of settlement of asset retirement obligations. Downward reserves revisions can also lead to significant impairment expense. The Company cannot predict the type of oil and natural gas reserves revisions that will be required in future periods. The Company's proved reserves of oil and natural gas are presented on pages F-48 and F-49 of this Form 10-K.

Murphy has utilized reliable geologic and engineering technology in 2011 and 2012 to include proved undeveloped reserves more than one location from producing wells in the more developed portions of the Eagle Ford Shale. The study incorporated public and proprietary data from multiple sources and encompassed the entire basin. This included analysis of seismic data, well log data, test production and fluids properties to establish geologic consistency as well as significant statistical performance data yielding predictable and repeatable reserves estimates within certain analogous areas. These locations were limited to only those areas with both established geologic consistency and sufficient statistical performance data where such data could be demonstrated to provide reasonably certain results.

Oil proved reserves revisions Proved oil reserves in the U.S. had positive revisions in 2012 which arose from improved performance in the Eagle Ford Shale area and at the Medusa field in the Gulf of Mexico. Negative conventional proved oil reserves revisions in Canada in 2012 occurred due to a lower recovery assessment for certain wells drilled in 51 -------------------------------------------------------------------------------- Table of Contents the Seal heavy oil area in Western Canada. Negative synthetic oil reserves revisions in 2012 at Syncrude were related to a change in entitlement that increased government royalties based on a recent projection for future operating and capital spending. The negative proved oil reserves revision in Republic of the Congo was associated with poor well performance, a well that prematurely went off production, and generally uneconomic remaining future production levels. In 2011, positive proved oil reserves revisions in the U.S. were primarily associated with better production at the Medusa field in the Gulf of Mexico. Positive 2011 revisions for oil reserves of conventional operations in Canada were mostly attributable to better well performance at the Hibernia field, offshore Eastern Canada. Synthetic oil operations had positive reserves revisions in 2011 due to a change in royalty rate. Positive oil reserves revisions in 2011 in Malaysia were primarily attributable to better production performance at the Kikeh field. Positive oil reserves revisions in the U.K. in 2011 were associated with the Schiehallion field which is being redeveloped by its owners. The negative revision in oil reserves in Republic of the Congo in 2011 was attributable to poor production results for wells in the field. In 2010, a positive revision in U.S. proved oil reserves was primarily associated with better than anticipated performance of wells at the Thunder Hawk and Medusa fields in the Gulf of Mexico. Better well performance at the Hibernia and Terra Nova fields led to favorable proved oil reserves revisions in Canada in 2010.

Proved oil reserves for Canadian synthetic oil operations had a positive revision in 2010 primarily due to a lower royalty. The positive proved oil reserves revision in Malaysia in 2010 primarily related to better well performance at the Kikeh field. A positive proved oil reserves revision in Republic of the Congo in 2010 was attributable to improved terms under the production sharing agreement that allocated a larger share of production at the Azurite field to the account of the Company beginning in October 2010.

Natural gas proved reserves revisions Proved natural gas reserves in the U.S. had positive revisions during 2012 due to improved well performance at several fields in the Gulf of Mexico, plus better well performance in the Eagle Ford Shale area. Proved natural gas reserves in Canada were revised downward in 2012 due to weaker average monthly natural gas prices in the current year that adversely affected certain areas in the Montney formation of Western Canada. Proved natural gas reserves in Malaysia in 2012 had positive revisions due to better well performance and favorable entitlement effects for gas operations offshore Sarawak. In 2011, proved natural gas reserves in the U.S. had negative revisions due to well performance being less than expected in early wells drilled in the gas-prone regions of the Eagle Ford Shale in South Texas. Positive gas reserves revisions in Canada in 2011 were primarily at the Tupper and Tupper West areas based on better than anticipated well performance. Negative gas reserves revisions in Malaysia in 2011 were primarily due to higher sales prices which effectively reduced the entitlement percentage for future production at the Sarawak gas fields. Negative gas reserves revisions in the U.K. in 2011 were essentially caused by revised estimate of gas-cap volumes at the Mungo/Monan field. In 2010, proved natural gas reserves in the U.S. had positive revisions due to better well performance at the Thunder Hawk and Mondo fields in the Gulf of Mexico. The positive gas reserves revision in Canada in 2010 was attributable to performance at various wells in the Tupper area of British Columbia. Proved reserves of natural gas in Malaysia were revised downward in 2010 due to higher prices leading to a lower future entitlement percentage for the Company. Positive gas reserves revisions in the U.K. in 2010 were attributable to better well performance at all gas producing fields.

• 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 and all development capital expenditures 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 cannot 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 52-------------------------------------------------------------------------------- Table of Contents 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. In 2012, a well in the MPN block offshore Republic of the Congo was expensed. This well had been drilled in late 2010 and was held until another well nearby could be drilled; the nearby well was unsuccessfully drilled in 2012. Also in 2012, two wells drilled offshore Sarawak in 2008 were expensed following local government denial of a request to extend the oil development period for these wells. Additionally in 2012, a well drilled in the Gulf of Mexico in 2010 was expensed following the owners' decision not to develop the well. In 2011, a dry hole was recorded for a well drilled in Republic of the Congo in 2009. A significant reduction in proved oil reserves at the Azurite field in the same MPS block during 2011 reduced the likelihood of this well being produced in future years. In 2010, a dry hole was recorded for a well in the North Sea that was drilled in 2008. Extensive evaluations of this oil discovery determined in 2010 that recovery of hydrocarbons was not economical in the current price environment.

• 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 or ethanol products produced and sold, and future inflation levels. The need to test a long-lived asset 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 revisions of oil or natural gas reserves, expected deterioration of future margins for refining, marketing or ethanol production operations, 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, marketing and ethanol production assets, the Company evaluates its properties when circumstances indicate that the 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. The Company recorded impairment expense in 2012 of $200.0 million for the Azurite field, offshore Republic of the Congo, and $61.0 million for the Hereford, Texas ethanol production facility. The Congo impairment was necessitated by removal of all proved oil reserves at Azurite following an unsuccessful redrill of a well; this result led to 53 -------------------------------------------------------------------------------- Table of Contents uneconomic future oil production operations for the field. The Hereford impairment was based on an expectation of continued weak future ethanol margins at the production facility. The Hereford impairment was determined using available years of futures prices for corn and ethanol, plus a terminal value based on a reasonable multiple of the final year's cash flow.

Impairment expense of $368.6 million was recognized in 2011 to reduce the carrying value of the Azurite oil field, offshore Republic of the Congo, to fair value. The expense was necessitated by a significant year-end 2011 reduction of proved oil reserves at this field which was caused by poor well performance. Based on an evaluation of expected future cash flows from properties at year-end 2012, the Company does not believe it had any other 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 often reflect higher expected prices for oil and natural gas in the future compared to the existing spot prices at the time of assessment. 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 2012. 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 and ethanol 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 cannot 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 and PM 311/312 in Malaysia and Blocks MPS and MPN in Republic of the Congo, for exploration licenses in certain areas, the largest of which are Australia, Indonesia and Brunei, and for 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. During 2012, the Company recognized U.S. tax benefits related to exploration activities in Republic of the Congo and Suriname that totaled $108.3 million. These U.S.

benefits arose due to tax deductions for worthless stock investments in these countries. 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.

• 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 based on the universe of high-quality corporate bonds that are available within each country. Cash flow analyses are performed in which a spot yield curve is used to discount projected benefit payment streams for the most significant plans. The discounted cash flows are used to determine an equivalent single rate which is the basis for selecting the discount rate within each country. 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.

54 -------------------------------------------------------------------------------- Table of Contents Based on bond yields at December 31, 2012, the Company has used a discount rate of 4.18% at year-end 2012 and beyond for the primary U.S. plans. The year-end 2012 discount rate is 0.69% lower than a year earlier; this reduced rate led to an increase in the Company's recorded liabilities for retirement plans compared to a year ago. 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 retirement plan expenses from wide swings in liabilities and asset valuations. The Company's normal annual retirement and postretirement plan expenses, excluding special termination benefits, are expected to increase slightly in 2013 compared to 2012 based on the effects of a growing employee base. In 2012, the Company paid $42.2 million into various retirement plans and $4.7 million into postretirement plans. In 2013, the Company is expecting to fund payments of approximately $42.9 million into various retirement plans and $5.6 million for postretirement plans. 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 return, or the health care cost trend rate increase is higher than expected. Although Congress recently passed the Moving Ahead for Progress in the 21st Century Act that permits certain companies to reduce retirement plan contributions in the near term, this Act does not reduce the Company's overall funding requirements in the long-term. 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 2013 annual retirement and postretirement expenses by $8.1 million and $1.0 million, respectively, and a 0.5% decline in the assumed rate of return on plan assets would increase 2013 retirement expense by $2.3 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 2012 under such contractual obligations and arrangements are shown below.

Amount of Obligations (Millions of dollars) Total 2013 2014-2015 2016-2017 After 2017 Total debt including current maturities $ 2,245.2 0.1 0.1 550.0 1,695.0 Operating and other lease obligations 1,764.1 225.8 425.1 264.1 849.1 Purchase obligations 3,826.1 2,489.6 1,153.9 162.6 20.0 Other long-term liabilities, including debt interest 2,311.7 143.8 308.3 285.1 1,574.5 Total $ 10,147.1 2,859.3 1,887.4 1,261.8 4,138.6 The Company has entered into agreements to lease production facilities for various producing oil fields. 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.

55-------------------------------------------------------------------------------- Table of Contents 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 amounts of commitments as of December 31, 2012 that expire in future periods are shown below.

Amount of Commitments (Millions of dollars) Total 2013 2014-2015 2016-2017 After 2017 Financial guarantees $ 7.8 - 3.2 1.2 3.4 Letters of credit 299.0 296.0 3.0 - - Total $ 306.8 296.0 6.2 1.2 3.4 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 2012 included operating leases of floating, production, storage and offloading vessels (FPSO) for the Kikeh and Azurite oil fields, operating leases for production facilities at the Thunder Hawk and West Patricia fields and for certain land and/or fueling stations in the U.K. and U.S., drilling contracts for onshore and offshore rigs in various countries, and oil and/or natural gas transportation contracts in the U.S. and Western Canada. The leases call for future monthly net lease payments through 2014 at Thunder Hawk, through 2016 at West Patricia and Azurite and through 2023 at Kikeh. The U.K. and U.S. fueling stations require monthly payments mostly over the next 20 years. The U.S. and Western Canada transportation contracts require minimum monthly payments through 2023. Future required minimum annual payments under these arrangements are included in the contractual obligation table shown on the preceding page.

In November 2012, the field's operator executed a 25 year lease for a semi-floating production system at the Kakap-Gumusut field offshore Sabah, Malaysia. This lease will become effective when the construction of the system is certified as complete, which is expected to occur in 2013. Although not legally liable under the lease until completion of construction and sail away, the Company has included the expected lease obligations for this production system in the contractual obligation table shown on the preceding page.

Outlook Prices for the Company's primary products are often quite volatile. The price for crude oil is primarily affected by the level of demand for energy. In January 2013, West Texas Intermediate crude oil traded in a band between $92 and $98 per barrel. NYMEX natural gas traded in a band of $3.10 to $3.55 per MMBTU during this same time. U.S. retail marketing margins in January 2012 were squeezed by higher wholesale gasoline prices and weaker seasonal driver demand for motor fuel products during this period. The Company continually monitors the prices for its main products and often alters its operations and spending based on these prices.

The Company's capital expenditure budget for 2013 was prepared during the fall of 2012 and based on this budget capital expenditures in 2013 are expected to be comparable to 2012 levels. Since the budget was approved by the Company's Board of Directors, crude oil prices have generally been above the levels assumed in the 2013 budget, but North American natural gas prices have generally trailed the budgeted prices. Capital expenditures in 2013 are projected to total approximately $4.3 billion. Of this amount, $4.1 billion or about 95%, is allocated for the exploration and production program. Geographically, E&P capital is spread approximately as follows: 41% for the United States, 38% for Malaysia, 13% for Canada and 8% for all other areas. Spending in the U.S. is primarily associated with development and exploration programs in the Eagle Ford Shale area of South Texas. In Malaysia, the majority of the spending is for continued development of the Kikeh, Kakap and Siakap fields in Block K and oil development projects offshore Sarawak in Blocks SK 309 and SK 311. Canadian spending is primarily related to continued development of the Seal heavy oil area and Syncrude. Refining and marketing expenditures in 2013 are budgeted at about $220 million, or 5% of the Company total, with the bulk of this spending allocated to construction of additional U.S. retail gasoline stations. Capital and other expenditures will 56 -------------------------------------------------------------------------------- Table of Contents be routinely reviewed during 2013 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 2013 using operating cash flow, but will supplement funding where necessary using borrowings under available credit facilities. The Company's 2013 budget calls for borrowings of long-term debt during the year to fund a portion of the capital program. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that higher than anticipated borrowings might be required during the year to maintain funding of the Company's ongoing development projects. Additionally, the 2013 budget assumes further share repurchases under the previously announced share buyback program of up to $1.0 billion. The level of these share repurchases is expected to influence the amount of borrowings under credit facilities during 2013.

The Company currently expects production in 2013 to average about 200,000 barrels of oil equivalent per day, a 3% increase compared to 2012. A key assumption in projecting the level of 2013 Company production is the anticipated ramp up of crude oil and natural gas production in the Eagle Ford Shale area of South Texas, where a major drilling and completion operation is ongoing with ten rigs in use. Another key factor in meeting 2013 production targets is the rate of decline of natural gas wells at the Tupper area in Western Canada. The Company significantly reduced development drilling operations in this area in 2012 and early 2013 due to depressed prices for Canadian natural gas production.

Due to the drilling cut back, natural gas production in the Tupper area will decline in 2013. Other key assumptions necessary to achieve the anticipated 2013 production levels include continued reliability of production at significant operations such as Kikeh, Syncrude, Hibernia and Terra Nova and the continued demand for natural gas from our offshore Malaysia fields.

The Company's 2013 budget anticipates an increase for overall hydrocarbon extraction costs by about $5.00 on a barrel of oil equivalent basis. Production costs in 2013 are projected to increase due to expected higher costs for synthetic oil operations at Syncrude caused by more spend on environmental and other regulatory matters, plus an unfavorable effect from a lower mix of Tupper area gas production, which is historically near the lowest cost per barrel equivalent produced by the Company. The overall per-unit depreciation rate for oil and gas operations is anticipated to rise in 2013 due to ongoing capital development costs at Kikeh, the Seal heavy oil area and Terra Nova.

Additionally, there is an unfavorable effect on the overall depreciation rate in 2013 from a lower mix of natural gas production in the Tupper area of Canada.

The Company has announced that it plans to exit the U.K. refining and marketing business. The sale process for this U.K. R&M business continues to progress in early 2013. In 2012, the Company announced its intention to separate its U.S.

downstream operations into a stand-alone publicly owned company. At the present time, this separation is expected to be completed in 2013. The Company also announced in 2012 that it would sell its U.K. oil and gas production assets; the sales are expected to be completed in early 2013. Further, the Company announced a stock repurchase program of up to $1.0 billion. Through year-end 2012, the Company had funded a $250 million accelerated share repurchase program with a major financial institution.

After the anticipated separation of the U.S. downstream subsidiary from Murphy Oil Corporation during 2013, and the desired sale of the U.K. downstream business, the Company is expected to be fundamentally different. The Company will have significantly lower sales revenue as the U.S. and U.K. downstream businesses generated about 84% of Murphy's consolidated revenue in 2012. For the year of 2012, the combined U.S. and U.K. downstream businesses generated about 15% of operating income from continuing operations before considering unallocated corporate net costs. Also, the two downstream businesses made up about 85% of the Company's workforce at year-end 2012. The Company also anticipates that without these downstream operations, it may no longer qualify as a member of the Fortune 500 group of companies. Murphy Oil is anticipated to be an independent oil and gas company in the future and will not have a significant refining and marketing business as a diversification to its oil and gas business. This decrease in size and change in diversification could impact its credit rating, and could, although not expected to, impact its ability to repay long-term debt obligations when due.

57-------------------------------------------------------------------------------- Table of Contents Forward-Looking Statements This Form 10-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, customer demand for our products, adverse foreign exchange movements, political and regulatory instability, and uncontrollable natural hazards. Factors that could cause the forecasted separation of its U.S. downstream business, as discussed in this Form 10-K, not to occur include, but are not limited to, a failure to obtain necessary regulatory approvals, a failure to obtain assurances of anticipated tax treatment, a deterioration in the business or prospects of Murphy or its U.S. downstream subsidiary, adverse developments in Murphy or its U.S. downstream subsidiary's markets, and adverse developments in the U.S. or global capital markets, credit markets or economies generally. Additionally, the Company may be unable to sell its U.K. downstream business as it desires to do because it may fail to execute a sale of these operations on acceptable terms.

For further discussion of risk factors, see Item 1A. Risk Factors, which begins on page 17 of this Annual Report on Form 10-K. Murphy undertakes no duty to publicly update or revise any forward-looking statements.

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