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.

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

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.

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

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

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.

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