10-K 1 d10k.htm FORM 10-K Form 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission file number 1-8590

 

 

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)

 

Delaware   71-0361522

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification Number)

 

200 Peach Street, P.O. Box 7000, El Dorado, Arkansas   71731-7000
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code: (870) 862-6411

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

 

Name of each exchange on which registered

Common Stock, $1.00 Par Value   New York Stock Exchange
Series A Participating Cumulative   New York Stock Exchange
Preferred Stock Purchase Rights  

Securities registered pursuant to Section 12(g) of the Act: None

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer   x    Accelerated filer   ¨
Non-accelerated filer   ¨    Smaller reporting company   ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter (as of June 30, 2010) – $9,503,357,000.

Number of shares of Common Stock, $1.00 Par Value, outstanding at January 31, 2011 was 192,853,864.

 

 

Documents incorporated by reference:

Portions of the Registrant’s definitive Proxy Statement relating to the Annual Meeting of Stockholders on May 11, 2011 have been incorporated by reference in Part III herein.

 

 

 

 


Table of Contents

MURPHY OIL CORPORATION

TABLE OF CONTENTS – 2010 FORM 10-K

 

         

Page

Number

 
PART I   

Item 1.

   Business      1   

Item 1A.

   Risk Factors      12   

Item 1B.

   Unresolved Staff Comments      15   

Item 2.

   Properties      15   

Item 3.

   Legal Proceedings      16   

Item 4.

   (Removed and Reserved)   
PART II   

Item 5.

   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities      17   

Item 6.

   Selected Financial Data      18   

Item 7.

   Management’s Discussion and Analysis of Financial Condition and Results of Operations      19   

Item 7A.

   Quantitative and Qualitative Disclosures About Market Risk      44   

Item 8.

   Financial Statements and Supplementary Data      44   

Item 9.

   Changes in and Disagreements With Accountants on Accounting and Financial Disclosure      45   

Item 9A.

   Controls and Procedures      45   

Item 9B.

   Other Information      45   
PART III   

Item 10.

   Directors, Executive Officers and Corporate Governance      45   

Item 11.

   Executive Compensation      45   

Item 12.

   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters      46   

Item 13.

   Certain Relationships and Related Transactions, and Director Independence      46   

Item 14.

   Principal Accounting Fees and Services      46   
PART IV   

Item 15.

   Exhibits, Financial Statement Schedules      46   

Signatures

     49   

 

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PART I

Item 1. BUSINESS

Summary

Murphy Oil Corporation is a worldwide oil and gas exploration and production company with refining and marketing operations in the United States and the United Kingdom. As used in this report, the terms Murphy, Murphy Oil, we, our, its and Company may refer to Murphy Oil Corporation or any one or more of its consolidated subsidiaries.

The Company was originally incorporated in Louisiana in 1950 as Murphy Corporation. It was reincorporated in Delaware in 1964, at which time it adopted the name Murphy Oil Corporation, and was reorganized in 1983 to operate primarily as a holding company of its various businesses. Its operations are classified into two business activities: (1) “Exploration and Production” and (2) “Refining and Marketing.” For reporting purposes, Murphy’s exploration and production activities are subdivided into six geographic segments, including the United States, Canada, Malaysia, the United Kingdom, Republic of the Congo and all other countries. Murphy’s refining and marketing activities are subdivided into segments for United States Manufacturing, United States Marketing and the United Kingdom. Additionally, “Corporate” activities include interest income, interest expense, foreign exchange effects and administrative costs not allocated to the segments.

The information appearing in the 2010 Annual Report to Security Holders (2010 Annual Report) is incorporated in this Form 10-K report as Exhibit 13 and is deemed to be filed as part of this Form 10-K report as indicated under Items 1, 2 and 7.

In addition to the following information about each business activity, data about Murphy’s operations, properties and business segments, including revenues by class of products and financial information by geographic area, are provided on pages 19 through 36, F-16 and F-17, F-41 through F-50 and F-52 of this Form 10-K report and on pages 5 and 6 of the 2010 Annual Report.

At December 31, 2010, Murphy had 8,994 employees, including 3,460 full-time and 5,534 part-time.

Interested parties may obtain the Company’s public disclosures filed with the Securities and Exchange Commission (SEC), including Form 10-K, Form 10-Q, Form 8-K and other documents, by accessing the Investor Relations section of Murphy Oil Corporation’s Web site at www.murphyoilcorp.com.

Exploration and Production

The Company’s exploration and production business explores for and produces crude oil, natural gas and natural gas liquids worldwide. The Company’s exploration and production management team in Houston, Texas, directs the Company’s worldwide exploration and production activities.

During 2010, Murphy’s principal exploration and production activities were conducted in the United States by wholly owned Murphy Exploration & Production Company – USA (Murphy Expro USA), in Malaysia, Republic of the Congo, Indonesia, Suriname, Australia, Brunei and the Kurdistan region of Iraq by wholly owned Murphy Exploration & Production Company – International (Murphy Expro International) and its subsidiaries, in Western Canada and offshore Eastern Canada by wholly owned Murphy Oil Company Ltd. (MOCL) and its subsidiaries, and in the U.K. North Sea and the Atlantic Margin by wholly owned Murphy Petroleum Limited. Murphy’s crude oil and natural gas liquids production in 2010 was in the United States, Canada, Malaysia, the United Kingdom and Republic of the Congo; its natural gas was produced and sold in the United States, Canada, Malaysia and the United Kingdom. MOCL owns a 5% undivided interest in Syncrude Canada Ltd. in northern Alberta, one of the world’s largest producers of synthetic crude oil.

Unless otherwise indicated, all references to the Company’s oil and gas production volumes and proved oil and gas reserves are net to the Company’s working interest excluding applicable royalties.

Murphy’s worldwide crude oil, condensate and natural gas liquids production in 2010 averaged 126,927 barrels per day, a decrease of 4% compared to 2009. The decrease was primarily due to lower 2010 oil production at the Kikeh field, offshore Sabah Malaysia. The Company’s worldwide sales volume of natural gas averaged almost 357 million cubic feet (MMCF) per day in 2010, up more than 90% from 2009 levels. The higher natural gas sales volume in 2010 was primarily attributable to increased natural gas production in three areas, the most significant of which was in Blocks SK 309/311,

 

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offshore Sarawak Malaysia. The other two primary growth areas for natural gas production in 2010 were at Tupper in British Columbia, Canada, and at the Kikeh field, offshore Sabah Malaysia. Total worldwide 2010 production on a barrel of oil equivalent basis (six thousand cubic feet of natural gas equals one barrel of oil) was 186,394 barrels per day, an increase of 14% compared to 2009.

Total production in 2011 is currently expected to average between 200,000 and 210,000 barrels of oil equivalent per day. The projected production increase of between 7% and 13% in 2011 is primarily related to new natural gas production at the Tupper West area in Western Canada that commenced in February 2011. These volumes will more than offset anticipated production declines in 2011 at fields in the Gulf of Mexico, and lower volumes associated with downtime for well maintenance at the Kikeh field, offshore Malaysia, and downtime for equipment maintenance at Terra Nova, offshore Newfoundland. Production levels in the Gulf of Mexico for Murphy, and likely many other companies, are being adversely affected by the inability to obtain government permits for drilling and well maintenance operations following the Macondo well blowout and oil spill by another company in 2010.

United States

In the United States, Murphy has production of oil and/or natural gas from six fields operated by the Company and five fields operated by others. The U.S. producing fields at December 31, 2010 include eight in the deepwater Gulf of Mexico, two onshore in Louisiana, and the Eagle Ford Shale area of South Texas. The Company produced approximately 20,100 barrels of oil per day and 53 million cubic feet of natural gas per day in the U.S. in 2010. These amounts represented 16% of the Company’s total worldwide oil and 15% of worldwide natural gas production volumes. During 2010, over 60% of total U.S. hydrocarbon production was produced at two operated Gulf of Mexico fields – Thunder Hawk and Medusa. Murphy has a 37.5% working interest in the Thunder Hawk field in Mississippi Canyon Block 734. Oil and natural gas production commenced at Thunder Hawk in July 2009 and during 2010 averaged about 9,800 barrels of oil per day and 9 MMCF per day. Production in 2011 at Thunder Hawk is expected to average approximately 5,500 barrels of oil per day and 8 MMCF per day. The lower 2011 production at Thunder Hawk is due to well decline and the inability to perform drilling operations since the Macondo incident in 2010. Proved oil and natural gas reserves at Thunder Hawk at year-end 2010 were 4.7 million barrels and 7.3 billion cubic feet, respectively. The Company holds a 60% interest at Medusa in Mississippi Canyon Blocks 538/582, which produced total daily oil and natural gas of about 5,500 barrels and 5 MMCF, respectively, in 2010. Production from Medusa is expected to continue to decline in 2011 and should average 4,300 barrels of oil and about 4 MMCF of natural gas on a daily basis. At December 31, 2010, the Medusa field has total proved oil and natural gas reserves of approximately 5.7 million barrels and 8.7 billion cubic feet, respectively. The Company has acquired rights to significant acreage in South Texas in the Eagle Ford Shale unconventional oil and gas play. The Company has drilled 17 wells through year-end 2010 of which 11 wells are capable of producing and the remaining six wells are pending completion. Initial well results in the Eagle Ford play have been encouraging. Current plans are to drill approximately 40 wells here in 2011. Total daily net production in 2011 in the Eagle Ford area is expected to amount to 4,300 barrels of oil and 13 MMCF of gas. Total U.S. oil and natural gas reserves at December 31, 2010 were 26.6 million barrels and 90.8 billion cubic feet, respectively.

Subsequent to the Macondo incident in April 2010, the process for obtaining drilling and other operational permits in the Gulf of Mexico has become uncertain. The changes to the permitting process, as well as operational procedures, are expected to cause delays and more expense associated with drilling operations in the Gulf of Mexico. Therefore, the Company anticipates that its production, and likely many other companies’ production, will decline in the Gulf of Mexico during 2011 and possibly into 2012. The Company is unable to predict to what extent these delays and new processes will ultimately impact its operations in the Gulf of Mexico.

Canada

In Canada, the Company owns an interest in three significant nonoperated assets – the Hibernia and Terra Nova fields offshore Newfoundland in the Jeanne d’Arc Basin and Syncrude Canada Ltd. in northern Alberta. In addition, the Company owns interests in one heavy oil area, two significant natural gas areas and light oil prospective acreage in the Western Canadian Sedimentary Basin (WCSB).

Murphy has a 6.5% working interest in Hibernia, while at Terra Nova the Company’s working interest has historically been 12.0%. The joint agreement between owners of Terra Nova required a one-time redetermination of working interests based on an analysis of reservoir quality among fault separated areas where varying ownership interests exist. The redetermination process was essentially completed in 2010 and the Company’s working interest was reduced to 10.475% effective January 1, 2011. The Company has recorded cumulative expense of $102.1 million through 2010 based on the anticipated settlement of the working interest reduction. The Company made a settlement payment to certain Terra Nova partners in January 2011 for the value of oil sold since about December 2004 related to the difference between the Company’s 10.475% ultimate working interest and its original 12.0% interest.

 

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Oil production in 2010 was about 6,300 barrels of oil per day at Hibernia and 5,200 barrels per day at Terra Nova. Hibernia production increased slightly in 2010 due to higher gross production mostly offset by a higher royalty rate, while production at Terra Nova declined primarily due to lower gross production. Oil production for 2011 at Hibernia is anticipated to be approximately 5,900 barrels per day and production at Terra Nova is expected to decline to approximately 3,000 barrels per day due to a scheduled 105 day turnaround. Total proved oil reserves at December 31, 2010 at Hibernia and Terra Nova were approximately 9.5 million barrels and 6.4 million barrels, respectively.

Murphy owns a 5% undivided interest in Syncrude Canada Ltd., a joint venture located about 25 miles north of Fort McMurray, Alberta. Syncrude utilizes its assets, which include three coking units, to extract bitumen from oil sand deposits and to upgrade this bitumen into a high-value synthetic crude oil. Production in 2010 was about 13,300 barrels of synthetic crude oil per day and is expected to average about 14,000 barrels per day in 2011. The SEC issued revised reserve rules in 2009 that permitted the reporting of proved reserves for synthetic oil operations beginning at year-end 2009. Prior to that time, the SEC considered Syncrude to be a mining operation rather than a conventional oil operation and therefore, did not allow the Company to include Syncrude’s reserves in its total proved oil reserves. Total proved reserves for Syncrude at year-end 2010 were 129.2 million barrels.

Daily production in 2010 in the WCSB averaged about 6,000 barrels of mostly heavy oil and about 85 MMCF of natural gas. Through 2010, the Company has acquired approximately 130,000 net acres of mineral rights in northeastern British Columbia in areas named Tupper and Tupper West. First production of natural gas occurred at Tupper in December 2008. The Company’s Board of Directors sanctioned development of Tupper West in 2009 and first production of natural gas occurred in February 2011. Oil and natural gas daily production for 2011 in Western Canada, excluding Syncrude, is expected to be about 8,600 barrels and 180 MMCF, respectively, with the increase in natural gas volumes primarily due to start-up of production at Tupper West in February 2011. Total Western Canada proved oil and natural gas reserves at December 31, 2010, excluding Syncrude, were 16.9 million barrels and 321.7 billion cubic feet, respectively.

During 2010, the Company added approximately 147,000 gross acres of land in Southern Alberta that is prospective for light oil. The Company began drilling operations on this acreage in early 2011. Additional wells are planned throughout 2011 to test various formations.

Malaysia

In Malaysia, the Company has majority interests in six separate production sharing contracts (PSCs). The Company serves as the operator of all these areas, which cover approximately 6.7 million gross acres. Murphy has an 85% interest in discoveries made in two shallow-water blocks, SK 309 and SK 311, offshore Sarawak. In January 2010, Murphy relinquished all other acreage in Blocks SK 309 and SK 311, while retaining the acreage surrounding its producing oil and gas fields as well as areas surrounding its other discoveries planned for future development. About 5,300 barrels of oil per day were produced in 2010 at Block SK 309/311, mostly at the West Patricia field. Oil production in 2011 at fields in Blocks SK 309/311 is anticipated to total about 5,300 barrels of oil per day. The Company has a gas sales contract for the Sarawak area with PETRONAS, the Malaysian state-owned oil company, and has prepared a multi-phase development plan for several natural gas discoveries on these blocks. The gas sales contract allows for gross sales volumes of up to 250 million cubic feet per day through 2014, with an option to extend for seven years at 250 million cubic feet per day or for ten years at 350 million cubic feet per day. Total natural gas sales volume offshore Sarawak was about 155 MMCF per day during 2010 (gross 210 MMCF per day) following gas production start-up in September 2009. Sarawak natural gas sales volumes are anticipated to be approximately 171 MMCF per day in 2011. Total proved reserves of oil and natural gas at December 31, 2010 for Blocks SK 309/311 were 5.8 million barrels and 348.1 billion cubic feet, respectively.

The Company made a major discovery at the Kikeh field in deepwater Block K, offshore Sabah, in 2002 and added another important discovery at Kakap in 2004. Several additional discoveries have been made in Block K at other areas. In 2006, the Company relinquished a portion of Block K and was granted a 60% interest in an extension of a portion of Block K. Total gross acreage held by the Company in Block K as of December 31, 2010 was 1.01 million acres. The Company retained its 80% interest at Kikeh, Kakap and other discoveries in Block K. First oil production from Kikeh began in August 2007, less than five years after the initial discovery. Production volumes at Kikeh averaged 61,600 barrels of oil per day during 2010. Oil production at Kikeh is anticipated to average approximately 57,000 barrels per day for 2011. In February 2007, the Company signed a Kikeh field natural gas sales contract with PETRONAS that calls for gross sales volumes of up to 120 million cubic feet per day through June 2012. Natural gas production at Kikeh began in late 2008,

 

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and 2010 production totaled approximately 58 MMCF per day. Daily gas production in 2011 at Kikeh is expected to be similar to 2010 levels. The Kakap field in Block K is operated by another company. This field is being jointly developed with the Gumusut field owned by others. Kakap development activities continued during 2010 and first production is anticipated in 2013. The Siakap North oil discovery was made in 2009; the field will be a unitized development and appraisal commenced in 2010. Total proved reserves booked in Block K as of year-end 2010 were 92.6 million barrels of oil and 85.9 billion cubic feet of natural gas.

In early 2006, the Company added a 60% interest in a PSC covering Block P, which includes 1.05 million gross acres of the previously relinquished Block K area, offshore Sabah. The Company also has an interest in deepwater Block H offshore Sabah. In early 2007, the Company announced a significant natural gas discovery at the Rotan well in Block H. In early 2008, the Company followed up Rotan with a discovery at Biris. In March 2008, the Company renewed the contract for Block H at a 60% interest while retaining 80% interest in the Rotan and Biris discoveries. In 2010 another natural gas discovery was made in Block H at Dolfin. Total gross acreage held at year-end 2010 by the Company in Block H was 1.99 million acres.

Murphy has a 75% interest in gas holding agreements for Kenarong and Pertang discoveries made in Block PM 311, located offshore peninsular Malaysia. Development options are being studied for these discoveries. Murphy relinquished its remaining interests in Block PM 311 and all of adjacent Block PM 312 in 2007.

The Company was awarded interests in two PSCs covering deepwater Blocks L (60%) and M (70%) in 2003. On April 7, 2010, the PSCs for Blocks L and M were terminated following execution of an Exchange of Letters between Malaysia and the Sultanate of Brunei on March 16, 2009. See further discussion about this exploration area in the Brunei section on page 5.

United Kingdom

Murphy produces oil and natural gas in the United Kingdom sector of the North Sea. Total 2010 production in the U.K. amounted to about 3,300 barrels of oil per day and 5 MMCF of natural gas per day. Total 2011 daily production levels in the U.K. are anticipated to average about 4,000 barrels of oil and 5 MMCF of natural gas. Total proved reserves in the U.K. at December 31, 2010 were 10.9 million barrels of oil and 31.4 billion cubic feet of natural gas.

Republic of the Congo

The Company has interests in Production Sharing Agreements (PSA) covering two offshore blocks in Republic of the Congo – Mer Profonde Sud (MPS) and Mer Profonde Nord (MPN). The Company’s interests cover approximately 1.33 million gross acres with water depths ranging from 490 to 6,900 feet, and the Company serves as operator of both blocks. In 2005, Murphy made an oil discovery at Azurite Marine #1 in the southern block, MPS. The Company successfully followed up the Azurite discovery with other appraisal wells. First oil production occurred at the Azurite field in August 2009. Total oil production in 2010 averaged 5,800 barrels per day at Azurite. Anticipated production in 2011 is 8,300 barrels per day, with the increase caused by additional producing wells in late 2010. Total proved oil reserves at the Azurite field as of December 31, 2010 were 10.1 million barrels. In late 2007, the Company sold down its interest in the MPS block, including the Azurite field, from 85% to 50%. Sale proceeds received were $94.5 million, including contingent amounts earned in 2009 upon achieving certain financial and operating goals for Azurite field development. In addition, the Company received a partial carry for costs for two exploration wells in MPS that were drilled in 2009, one of which was a discovery known as Turquoise Marine. Two subsequent wells at Turquoise and one at another prospect were unsuccessful. Further drilling activities are being planned for the Turquoise discovery area. A wildcat well drilled at Titane Marine in 2010 in the MPN block found accumulations of crude oil for which appraisal plans are pending. Development options are currently being studied. Other prospects in the MPN and MPS blocks are being evaluated and exploration wells are planned for 2011 and 2012.

In late 2010, the Company successfully negotiated an amendment to the PSA covering the MPS block. The new terms were officially approved in February 2011 and are effective retroactive to October 1, 2010. Essentially, the PSC amendment calls for revised terms that will permit additional levels of crude oil production to be allocated to the accounts of the Company and its non-government partners in future periods. The Company is also required to pay a bonus to Republic of the Congo in connection with the PSA amendment.

Suriname

In June 2007, Murphy entered into a production sharing contract covering Block 37, offshore Suriname. Murphy operates this block and has a 100% working interest, subject to a potential reduction to 80% should the state oil company exercise

 

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its option. Block 37 covers approximately 2.16 million gross acres and has water depths ranging from 160 to 1,000 feet. In the acreage table on page 8, the Company has reflected net acreage for Suriname as if the state company’s option will be exercised. The contract provides for a six-year exploration period with two phases. Phase I has a four-year period that requires the acquisition of 3D seismic and the drilling of two wells. The 3D seismic was shot in late 2008 and early 2009, and interpretation of this data occurred in 2009. The first exploration well was drilled in late 2010 and was unsuccessful. A second exploration well will be drilled in early 2011.

Australia

The Company acquired a 40% interest and operatorship of an exploration permit covering approximately 1.00 million gross acres in Block AC/P36 in the Browse Basin offshore northwestern Australia in November 2007. Three-dimensional seismic data was obtained in late 2007 and drilling of a commitment exploration well in late 2008 was unsuccessful. In November 2008, the Company acquired a 70% working interest and operatorship of a second Browse Basin exploration permit in Block WA-423-P. Murphy farmed down its interest in WA-423-P to 40% in the first quarter of 2009. This permit covers approximately 1.43 million gross acres and calls for a 3D seismic survey and one exploration well, which is expected to be drilled in 2011. In June 2009, the Company acquired a 70% interest and operatorship of Block NT/P80 in the Bonaparte Basin, offshore northwestern Australia. The block covers approximately 1.21 million gross acres and reprocessing of seismic covering the area has been completed. In 2010, the Company sold down its interest in this block to 40%.

Indonesia

In May 2008, the Company entered into a production sharing contract in Indonesia covering a 100% interest in the South Barito block in south Kalimantan on the island of Borneo. The block covers approximately 1.24 million gross acres. The contract permits a six-year exploration term with an optional four-year extension. The work commitment calls for geophysical work, 2D seismic acquisition and processing, and two exploration wells. The contract requires relinquishment of 25% of acreage after three years and an additional 55% after six years. In November 2008, Murphy entered into a production sharing contract in the Semai II Block offshore West Papua. The Company has a 28% interest in the block which covers about 835,000 gross acres. The permit calls for a 3D seismic program and three exploration wells. The first exploration well in the Semai II Block was being drilled in early 2011. In December 2010, Murphy entered into a production sharing contract in the Wokam II Block offshore West Papua, Moluccas and Papua. Murphy has a 100% interest in the block which covers 1.22 million gross acres. The three-year work commitment calls for geophysical and 3D seismic acquisition and processing. Murphy is the operator of the South Barito, Semai II and Wokam II concessions.

Brunei

In late 2010, the Company entered into two production sharing agreements for properties offshore Brunei. The Company has a 5% working interest in Block CA-1 and a 30% working interest in Block CA-2. These blocks cover a significant portion of acreage formerly held by the Company in Malaysia Blocks L and M. The Malaysian Production Sharing Contracts covering Blocks L and M were terminated in early 2010. The CA-1 and CA-2 blocks cover 1.45 million and 1.49 million gross acres, respectively.

Kurdistan region of Iraq

In late 2010, the Company finalized an agreement with the Kurdistan Regional Government in Iraq to acquire an interest in the Central Dohuk Block. The Company will operate and hold a 50% interest in the block. The Central Dohuk block covers approximately 153 thousand gross acres and is located in the Dohuk area of the Kurdistan region in Iraq. The Company plans to shoot seismic in 2011 with an exploration well to follow in 2012.

Ecuador

Murphy sold its 20% working interest in Block 16, Ecuador in March 2009. The Company has accounted for all Ecuador operations as discontinued operations. In October 2007, the government of Ecuador passed a law that increased its share of revenue for sales prices that exceed a base price (about $23.36 per barrel at December 31, 2008) from 50% to 99%. The government had previously enacted a 50% revenue sharing rate in April 2006. The Company has initiated arbitration proceedings against the government claiming that they did not have the right under the contract to enact the revenue sharing provision. In 2010, the arbitration panel determined that it lacked jurisdiction over the claim due to technicalities. The arbitration is expected to be refiled in 2011 and is likely to take many months to reach conclusion. The Company’s total claim in the arbitration process is approximately $118 million.

 

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Total proved oil and gas reserves as of December 31, 2010 are presented in the following table.

 

            Proved Reserves  
     Oil      Synthetic Oil      Natural Gas  
            (millions of barrels)      (billions of cubic feet)  

Proved Developed:

        

United States

     15.8         —           67.0   

Canada

     28.6         119.1         210.1   

Malaysia

     66.5         —           277.5   

United Kingdom

     10.9         —           31.4   

Republic of the Congo

     7.4         —           —     
                          

Total proved developed

     129.2         119.1         586.0   
                          

Proved Undeveloped:

        

United States

     10.8         —           23.8   

Canada

     4.2         10.1         116.8   

Malaysia

     31.9         —           156.5   

United Kingdom

     —           —           —     

Republic of the Congo

     2.7         —           —     
                          

Total proved undeveloped

     49.6         10.1         297.1   
                          

Total proved

     178.8         129.2         883.1   
                          

Proved Undeveloped Reserves

Murphy’s proved undeveloped reserves at December 31, 2010 increased 7.0 million barrels of oil equivalent (MMBOE) from a year earlier. Approximately 33.6 MMBOE of proved undeveloped reserves were converted to proved developed reserves during 2010. The majority of the proved undeveloped reserves migration to the proved developed category occurred at the Sarawak gas fields and in the Tupper and Tupper West gas areas, as these areas had active development work ongoing during the year. The conversion of non-proved reserves to newly reported proved undeveloped reserves occurred at several areas including, but not limited to, the Tupper, Tupper West and Eagle Ford Shale areas and the Kikeh field. During 2010, there were 15.9 MMBOE of positive revisions for proved undeveloped reserves. The majority of proved undeveloped reserves additions associated with revisions of previous estimates were the result of development drilling and well performance at the Kikeh field in Malaysia. The Company spent $399 million in 2010 to convert proved undeveloped reserves to proved developed reserves. The Company expects to spend about $961 million in 2011, $346 million in 2012 and $136 million in 2013 to move currently undeveloped proved reserves to the developed category. The higher level of spend in 2011 is caused by significant drilling in the year at Kikeh field and in the Tupper and Tupper West areas. In computing MMBOE, natural gas is converted to equivalent barrels of oil using a ratio of six thousand cubic feet (MCF) to one barrel of oil.

At December 31, 2010, proved reserves are included for several development projects that are ongoing, including natural gas developments at the Tupper West area in British Columbia and offshore Sarawak in Malaysia, and an oil development at Kakap, offshore Sabah Malaysia. Total proved undeveloped reserves associated with various development projects at December 31, 2010 were approximately 109 million barrels of oil equivalents, which is 24% of the Company’s total proved reserves. Certain of these development projects have proved undeveloped reserves that will take more than five years to bring to production. Two such projects have significant levels of such proved undeveloped reserves. The Company operates a deepwater field in the Gulf of Mexico that has two undeveloped locations that exceed this five-year window. Total reserves associated with the two wells amount to less than 2% of the Company’s total proved reserves at year-end 2010. The development of certain of this field’s reserves stretches beyond five years due to limited well slots available on the production platform, thus making it necessary to wait for depletion of other wells prior to initiating further development of these two locations. The Kakap field oil development project has undeveloped proved reserves that make up approximately 3% of the Company’s total proved reserves at year-end 2010. This non-operated project will take longer than five years to develop due to long lead-time equipment required to complete the development process.

Murphy Oil’s Reserves Processes and Policies

Murphy provides annual training to all company reserve estimators to ensure SEC requirements associated with reserve estimation and associated Form 10-K reporting are fulfilled. The training includes a Company manual provided to each participant that outlines the latest guidance from the SEC as well as best practices for many engineering and geologic matters related to reserve estimation.

 

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The Company employs a Manager of Corporate Reserves (Manager) who is independent of the Company’s oil and gas management. The Manager reports to a Senior Vice President of Murphy Oil Corporation, who in turn reports directly to the President of the Company. The Manager makes presentations to the Board of Directors periodically about the Company’s reserves. The Manager reviews and discusses reserves estimates directly with the Company’s reservoir engineering staff in order to make every effort to ensure compliance with the rules and regulations of the SEC and industry. The Manager coordinates and oversees internal reserves audits. These audits are performed annually and target coverage of approximately one-third of Company reserves each year. The audits are performed by the Manager and qualified engineering staff from areas of the Company other than the area being audited. The Manager may also utilize qualified independent reserves consultants to assist with the internal audits or to perform separate audits as considered appropriate. The Company does not rely on independent reserves consultants to determine its proved reserves reported in this Form 10-K.

Each significant exploration and production office maintains one or more Qualified Reserve Estimators (QRE) on staff. The QRE is responsible for estimating and evaluating reserves and other reserves information for his or her assigned area. The QRE may personally make the estimates and evaluations of reserves or may supervise and approve the estimation and evaluation thereof by others. A QRE is professionally qualified to perform these reserves estimates due to having sufficient educational background, professional training and professional experience to enable him or her to exercise prudent professional judgment. Normally, this requires a minimum of three years practical experience in petroleum engineering or petroleum production geology, with at least one year of such experience being in the estimation and evaluation of reserves, and either a bachelors or advanced degree in petroleum engineering, geology or other discipline of engineering or physical science from a college or university of recognized stature, or the equivalent thereof from an appropriate government authority or professional organization.

Larger Company offices also employ a Regional Reserves Coordinator (RRC) who supervises the local QREs. The RRC is usually a senior QRE that has the primary responsibility for coordinating and submitting reserves information to senior management.

The Company’s QREs maintain files containing pertinent data regarding each significant reservoir. Each file includes sufficient data to support the calculations or analogies used to develop the values. Examples of data included in the file, as appropriate, include: production histories; pertinent drilling and workover histories; bottom hole pressure data; volumetric, material balance, analogy or other pertinent reserve estimation data; production performance curves; narrative descriptions of the methods and logic used to determine reserves values; maps and logs; and a signed copy of the conclusion of the QRE stating, that in their opinion, the reserves have been calculated, reviewed, documented and reported in compliance with the regulations and guidelines contained in the reserves training manual. The Company’s reserves are maintained in an industry recognized reservoir engineering software system, which has adequate access controls to avoid the possibility of improper manipulation of data.

When reserves calculations are completed by QREs and appropriately reviewed by RRCs and the Manager, the conclusions are reviewed and discussed with the head of the Company’s exploration and production business and other senior management as appropriate. The Company’s Controller’s department is responsible for preparing and filing reserves schedules within Form 10-K.

Qualifications of Manager of Corporate Reserves

The Company believes that it has qualified employees generating oil and gas reserves. Mr. Brad Gouge serves as Manager of Corporate Reserves after joining the Company in mid-2008. Prior to that time, Mr. Gouge was Vice President of a major petroleum engineering consulting firm. He previously was a reservoir and production engineer with a major integrated oil company. Mr. Gouge earned a Bachelors of Science degree in Petroleum Engineering from Texas A&M University and has attended numerous industry training courses. Mr. Gouge is a registered Professional Engineer in the state of Texas and is an instructor for a Society of Petroleum Engineers (SPE) Petroleum Reserves course. He is also co-author of two papers on reservoir engineering which have been published by the SPE.

More information regarding Murphy’s estimated quantities of proved oil and gas reserves for the last three years are presented by geographic area on pages F-46 and F-47 of this Form 10-K report. Murphy has not filed and is not required to file any estimates of its total proved oil or gas reserves on a recurring basis with any federal or foreign governmental regulatory authority or agency other than the U.S. Securities and Exchange Commission. Annually, Murphy reports gross reserves of properties operated in the United States to the U.S. Department of Energy; such reserves are derived from the same data from which estimated proved reserves of such properties are determined.

 

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Crude oil, condensate and gas liquids production and sales, and natural gas sales by geographic area with weighted average sales prices for each of the seven years ended December 31, 2010 are shown on page 5 of the 2010 Annual Report. In 2010, the Company’s production of oil and natural gas represented approximately 0.1% of worldwide totals.

Production expenses for the last three years in U.S. dollars per equivalent barrel are discussed beginning on page 26 of this Form 10-K report. For purposes of these computations, natural gas sales volumes are converted to equivalent barrels of oil using a ratio of six MCF of natural gas to one barrel of oil.

Supplemental disclosures relating to oil and gas producing activities are reported on pages F-44 through F-52 of this Form 10-K report.

At December 31, 2010, Murphy held leases, concessions, contracts or permits on developed and undeveloped acreage as shown by geographic area in the following table. Gross acres are those in which all or part of the working interest is owned by Murphy. Net acres are the portions of the gross acres attributable to Murphy’s interest.

 

     Developed      Undeveloped      Total  

Area (Thousands of acres)

   Gross      Net      Gross      Net      Gross      Net  

United States – Onshore

     9         7         267         229         276         236   

    – Gulf of Mexico

     14         5         1,051         627         1,065         632   

    – Alaska

     4         1         3         —           7         1   
                                                     

Total United States

     27         13         1,321         856         1,348         869   
                                                     

Canada – Onshore, excluding oil sands

     36         30         494         446         530         476   

    – Offshore

     89         8         46         3         135         11   

    – Oil sands – Syncrude

     96         5         160         8         256         13   
                                                     

Total Canada

     221         43         700         457         921         500   
                                                     

Malaysia

     9         8         6,687         4,211         6,696         4,219   

United Kingdom

     34         4         31         4         65         8   

Republic of the Congo

     1         —           1,333         902         1,334         902   

Suriname

     —           —           2,164         1,731         2,164         1,731   

Australia

     —           —           3,640         1,456         3,640         1,456   

Indonesia

     —           —           3,301         2,432         3,301         2,432   

Brunei

     —           —           2,936         519         2,936         519   

Kurdistan (Iraq)

     —           —           153         76         153         76   

Spain

     —           —           36         6         36         6   
                                                     

Totals

     292         68         22,302         12,650         22,594         12,718   
                                                     

Certain acreage held by the Company will expire in the next three years. Scheduled expirations in 2011 include 401 thousand net acres in Block AC/P36, Australia; 279 thousand acres in South Barito and 75 thousand net acres in Semai II in Indonesia; 346 thousand net acres in Block 37 Suriname; 563 thousand net acres in Block K Malaysia; 356 thousand net acres in Block H Malaysia; and 448 thousand net acres in Blocks MPS and MPN in Republic of the Congo. In 2012, 82 thousand net acres expire in Blocks SK 309 and SK 311 Malaysia; 36 thousand net acres expire in Block PM 311 in Malaysia; and 182 thousand net acres expire in the United States. In 2013, 841 thousand net acres expire in Block H Malaysia; 627 thousand net acres expire in Block P Malaysia; and 161 thousand net acres expire in the United States.

As used in the three tables that follow, “gross” wells are the total wells in which all or part of the working interest is owned by Murphy, and “net” wells are the total of the Company’s fractional working interests in gross wells expressed as the equivalent number of wholly owned wells.

 

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The following table shows the number of oil and gas wells producing or capable of producing at December 31, 2010.

 

     Oil Wells      Gas Wells  

Country

   Gross      Net      Gross      Net  

United States

     46         15         18         10   

Canada

     313         216         104         104   

Malaysia

     32         26         20         17   

United Kingdom

     36         3         23         2   

Republic of the Congo

     6         3         —           —     
                                   

Totals

     433         263         165         133   
                                   

Murphy’s net wells drilled in the last three years are shown in the following table.

 

     United
States
     Canada      Malaysia      United
Kingdom
     Other      Total  
     Productive      Dry      Productive      Dry      Productive      Dry      Productive      Dry      Productive      Dry      Productive      Dry  

2010

                                   

Exploratory

     9.2         —           —           —           6.8         0.8         —           0.1         1.0         2.5         17.0         3.4   

Development

     —           —           87.0         5.0         23.6         —           —           —           2.5         —           113.1         5.0   

2009

                                   

Exploratory

     1.3         0.6         —           —           5.6         1.6         —           —           0.5         0.7         7.4         2.9   

Development

     1.1         —           42.0         3.0         17.0         —           0.4         —           0.5         —           61.0         3.0   

2008

                                   

Exploratory

     1.7         1.5         —           —           0.8         4.6         0.2         —           —           —           2.7         6.1   

Development

     0.8         —           64.4         1.0         9.9         —           0.2         0.1         0.4         —           75.7         1.1   

Murphy’s drilling wells in progress at December 31, 2010 are shown below.

 

     Exploratory      Development      Total  

Country

   Gross      Net      Gross      Net      Gross      Net  

United States

     6.0         4.2         —           —           6.0         4.2   

Canada

     —           —           5.0         4.5         5.0         4.5   

Malaysia

     1.0         .9         1.0         .8         2.0         1.7   

Republic of the Congo

     —           —           1.0         .5         1.0         .5   

Indonesia

     1.0         .3         —           —           1.0         .3   
                                                     

Totals

     8.0         5.4         7.0         5.8         15.0         11.2   
                                                     

Refining and Marketing

The Company’s refining and marketing businesses are located in the United States and the United Kingdom, and primarily consist of operations that refine crude oil and other feedstocks into petroleum products such as gasoline and distillates, buy and sell crude oil and refined products, and transport and market petroleum products. The Company has announced its intention to sell its U.S. refineries and U.K. refining and marketing operations in 2011. The Company acquired an ethanol production facility in North Dakota during 2009, and also purchased an unfinished ethanol production facility in Texas in 2010.

Murphy Oil USA, Inc. (MOUSA), a wholly owned subsidiary of Murphy Oil Corporation, owns and operates two refineries in the United States. The larger of its U.S. refineries is at Meraux, Louisiana, on the Mississippi River approximately 10 miles southeast of New Orleans. The Company owns a smaller refinery at Superior, Wisconsin. Both U.S. refineries are located on fee land. Murco Petroleum Limited (Murco), a wholly owned U.K. subsidiary, owns 100% interest in a refinery at Milford Haven, Wales, which is primarily located on fee land. Murco acquired the remaining 70% of the Milford Haven refinery that it did not already own on December 1, 2007.

 

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Refinery capacities at December 31, 2010 are shown in the following table.

 

     Meraux,
Louisiana
     Superior,
Wisconsin
     Milford Haven,
Wales
     Total  

Crude capacity – b/sd*

     125,000         35,000         135,000         295,000   

Process capacity – b/sd*

           

Vacuum distillation

     50,000         20,500         55,000         125,500   

Catalytic cracking – fresh feed

     37,000         11,000         37,000         85,000   

Naphtha hydrotreating

     35,000         11,000         18,300         64,300   

Catalytic reforming

     32,000         8,000         18,300         58,300   

Gasoline hydrotreating

     —           7,500         —           7,500   

Distillate hydrotreating

     52,000         11,200         74,000         137,200   

Hydrocracking

     32,000         —           —           32,000   

Gas oil hydrotreating

     12,000         —           —           12,000   

Solvent deasphalting

     18,000         —           —           18,000   

Isomerization

     —           —           11,300         11,300   

Production capacity – b/sd*

           

Alkylation

     8,500         1,600         6,300         16,400   

Asphalt

     —           7,500         —           7,500   

Crude oil and product storage capacity – barrels

     3,446,000         3,114,000         8,908,000         15,468,000   

 

* Barrels per stream day.

In 2003, Murphy expanded the refinery at Meraux, Louisiana. The expansion included a new hydrocracker unit; an increase of the crude oil processing capacity to 125,000 barrels per stream day (b/sd); an increase to the naphtha hydrotreating capacity to 35,000 b/sd; an increase to the catalytic reforming capacity to 32,000 b/sd; construction of a new sulfur recovery complex, with amine regeneration, sour water stripping and high efficiency sulfur recovery; a new central control room; and two new utility boilers. In 2010, a new laboratory was completed and various units were debottlenecked at Meraux. The Meraux refinery underwent a full plant turnaround in early 2010. At the Superior, Wisconsin, refinery, the Company completed the addition of a fluid catalytic cracking gasoline hydrotreater unit in 2004. In 2006, the isomerization unit at the Superior refinery was converted to a hydrotreater and one of two existing naptha hydrotreaters was converted to a kerosine hydrotreater. In 2010, Superior completed an ultra-low sulfur diesel revamp on its distillate hydrotreaters, which expanded capability of distillate production. Both U.S. refineries are capable of meeting mandatory low-sulfur gasoline and distillate products specifications.

In late August 2005, the Meraux refinery and associated assets were severely damaged by flooding and high winds caused by Hurricane Katrina. The majority of costs to repair the Meraux refinery were covered by insurance. The Company recorded expenses for repair costs not expected to be recoverable from insurance of $50.7 million in 2006 and a further $3.0 million in 2007. The final insurance settlement related to the property damages and repairs was completed in 2009 and income of $12.7 million was recorded in 2009 associated with actual insurance recoveries that exceeded amounts estimated in prior years to be recoverable.

MOUSA markets refined products through a network of retail gasoline stations and branded and unbranded wholesale customers in a 26-state area, primarily in the Southern and Midwestern United States. Murphy’s retail stations are located in 22 states and are primarily located in the parking lots of Walmart Supercenters using the brand name Murphy USA®. The Company’s stations also include stand-alone locations using the Murphy Express® brand. Branded wholesale customers use the brand name SPUR®. At December 31, 2010, the Company marketed products through 1,099 Murphy owned and operated stations and 116 branded wholesale SPUR stations. Of the Company stations, 1,001 are located on parking lots of Walmart Supercenters and 98 are stand-alone Murphy Express locations. MOUSA plans to build additional retail gasoline stations at Walmart Supercenters and other stand-alone locations in 2011 and beyond. Refined products are supplied from 12 terminals that are wholly owned and operated by MOUSA, two terminals that are leased by Murphy and numerous terminals owned by others. Three of the wholly owned terminals are supplied by marine transportation, three are supplied by truck, four are supplied by pipeline and two are adjacent to MOUSA’s refineries. MOUSA also receives products at terminals owned by others either in exchange for deliveries from the Company’s terminals or by outright purchase. Six owned terminals and the rights to use two leased terminals are included as a component of the refinery assets held for sale in the U.S.

 

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The Company owns land underlying 873 of the stations on Walmart parking lots. No rent is payable to Walmart for the owned locations. For the remaining gasoline stations located on Walmart property that are not owned, Murphy has master agreements that allow the Company to rent land from Walmart. The master agreements contain general terms applicable to all rental sites in the United States. The terms of the agreements range from 10-15 years at each station, with Murphy holding two successive five-year extension options at each site. The agreements permit Walmart to terminate the agreements in their entirety, or only as to affected sites, at its option for the following reasons: Murphy vacates or abandons the property; Murphy improperly transfers the rights under this agreement to another party; an agreement or a premises is taken upon execution or by process of law; Murphy files a petition in bankruptcy or becomes insolvent; Murphy fails to pay its debts as they become due; Murphy fails to pay rent or other sums required to be paid within 90 days after written notice; or Murphy fails to perform in any material way as required by the agreements. Sales from the Company’s U.S. retail marketing stations represented 45.9% of consolidated Company revenues in 2010, 45.7% in 2009 and 42.7% in 2008. As the Company continues to expand the number of retail operated gasoline stations, total revenue generated by this business is expected to grow.

In October 2009, MOUSA acquired an ethanol production facility located in Hankinson, North Dakota. The $92 million purchase price was primarily financed by $82 million of seller-provided nonrecourse debt. The Company chose in 2010 to pay off the nonrecourse debt early. The facility is designed to produce 110 million gallons of corn-based ethanol per year. Ethanol production in 2010, the first full year of operation, totaled more than 115 million gallons at Hankinson. The Company acquired a partially constructed ethanol production facility in Hereford, Texas, in late 2010. The Company paid $40 million for the facility at purchase and expects to spend approximately $25 million to complete construction of the facility. The facility is designed with production capacity of 105 million gallons of corn-based ethanol per year, and it is expected to be in operation near the end of the first quarter of 2011.

Murphy owns a 20% interest in a 120-mile refined products pipeline, with a capacity of 165,000 barrels per day, that transports products from the Meraux refinery to two common carrier pipelines serving the southeastern United States. The Company also owns a 3.2% interest in the Louisiana Offshore Oil Port LLC (LOOP), which provides deepwater unloading accommodations off the Louisiana coast for oil tankers and onshore facilities for storage of crude oil. A crude oil pipeline with a diameter of 24 inches connects LOOP storage at Clovelly, Louisiana, to the Meraux refinery. Murphy owns a 40.1% interest in the first 22 miles of this pipeline from Clovelly to Alliance, Louisiana, and 100% of the remaining 24 miles from Alliance to Meraux.

The Milford Haven, Wales, refinery was shut down for a plant-wide turnaround in early 2010. During the downtime, the Company completed an expansion project that increased the plant’s crude oil throughput capacity from 108,000 barrels per day to 135,000 barrels per day.

At the end of 2010, Murco distributed refined products in the United Kingdom from the wholly-owned Milford Haven refinery, three wholly owned terminals supplied by rail, six terminals owned by others where products are received in exchange for deliveries from the Company’s terminals and eight terminals owned by others where products are purchased for delivery. At December 31, 2010, there were 234 Company stations, 209 of which were branded MURCO with the remainder under various third party brands. The Company owns the freehold under 151 of the sites and leases the remainder. The Company supplies 217 MURCO branded dealer stations.

In 2010, Murphy owned approximately 1.0% of the crude oil refining capacity in the United States and 7.5% of the refining capacity in the United Kingdom. The Company’s market share of U.S. retail gasoline sales was approximately 2.7% in 2010 and in the U.K. Murphy’s fuel sales represented 2.1% of the total market share.

A statistical summary of key operating and financial indicators for each of the seven years ended December 31, 2010 are reported on page 6 of the 2010 Annual Report.

Environmental

Murphy’s businesses are subject to various U.S. federal, state and local environmental, health and safety laws and regulations, and are also subject to similar laws and regulations in other countries in which it operates. These regulatory requirements continue to change and increase in number and complexity, and the requirements govern the manner in which the company conducts its operations and the products it sells. The Company anticipates more environmental regulations in the future in the countries where it has operations.

 

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Further information on environmental matters and their impact on Murphy are contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 33 through 36.

Web site Access to SEC Reports

Our Internet Web site address is http://www.murphyoilcorp.com. Information contained on our Web site is not part of this report on Form 10-K.

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on our Web site, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC. Alternatively, you may access these reports at the SEC’s Web site at http://www.sec.gov.

Item 1A. RISK FACTORS

Murphy Oil’s businesses operate in highly competitive environments, which could adversely affect it in many ways, including its profitability, its ability to grow, and its ability to manage its businesses.

Murphy operates in the oil and gas industry and experiences intense competition from other oil and gas companies, which include state-owned foreign oil companies, major integrated oil companies, independent producers of oil and natural gas and independent refining and marketing companies. Virtually all of the state-owned and major integrated oil companies and many of the independent producers and refiners that compete with the Company have substantially greater resources than Murphy. In addition, the oil industry as a whole competes with other industries in supplying energy requirements around the world. Murphy competes, among other things, for valuable acreage positions, exploration licenses, drilling equipment and human resources.

If Murphy cannot replace its oil and natural gas reserves, it will not be able to sustain or grow its business.

Murphy continually depletes its oil and natural gas reserves as production occurs. In order to sustain and grow its business, the Company must successfully replace the crude oil and natural gas it produces with additional reserves. Therefore, it must create and maintain a portfolio of good prospects for future reserve additions and production by obtaining rights to explore for, develop and produce hydrocarbons in promising areas. In addition, it must find, develop and produce and/or purchase reserves at a competitive cost structure to be successful in the long-term. Murphy’s ability to operate profitably in the exploration and production segments of its business, therefore, is dependent on its ability to find, develop and produce and/or purchase oil and natural gas reserves at costs that are less than the realized sales price for these products and at costs competitive with competing companies in the industry.

Murphy’s proved reserves are based on the professional judgment of its engineers and may be subject to revision.

Proved oil and natural gas reserves included in this report on pages F-46 and F-47 have been prepared by Company personnel based on an unweighted average of oil and natural gas prices in effect at the beginning of each month in 2010 as well as other conditions and information available at the time the estimates were prepared. Estimation of reserves is a subjective process that involves professional judgment by engineers about volumes to be recovered in future periods from underground crude oil and natural gas reservoirs. Estimates of economically recoverable crude oil and natural gas reserves and future net cash flows depend upon a number of variable factors and assumptions, and consequently, different engineers could arrive at different estimates of reserves and future net cash flows based on the same available data and using industry accepted engineering practices and scientific methods. Under existing Securities and Exchange Commission rules, reported proved reserves must be reasonably certain of recovery in future periods.

Actual future crude oil and natural gas production may vary substantially from the reported quantity of our proved reserves due to a number of factors, including:

 

   

Oil and natural gas prices which are materially different than prices used to compute proved reserves

 

   

Operating and/or capital costs which are materially different than those assumed to compute proved reserves

 

   

Future reservoir performance which is materially different from models used to compute proved reserves, and

 

   

Governmental regulations or actions which materially change operations of a field.

 

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The Company’s proved undeveloped reserves represent significant portions of total proved reserves. As of December 31, 2010, approximately 19% of the Company’s proved oil reserves and 34% of proved natural gas reserves are undeveloped. The ability of the Company to reclassify these undeveloped proved reserves to the proved developed classification is generally dependent on the successful completion of one or more operations, which might include further development drilling, construction of facilities or pipelines, and well workovers.

The discounted future net revenues from our proved reserves should not be considered as the market value of the reserves attributable to our properties. As required by generally accepted accounting principles, the estimated discounted future net revenues from our proved reserves are based on an unweighted average of the oil and natural gas prices in effect at the beginning of each month during the year. Actual future prices and costs may be materially higher or lower than those used in the reserves computations. In addition, the 10 percent discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under generally accepted accounting principles is not necessarily the most appropriate discount factor based on our cost of capital and the risks associated with our business and the crude oil and natural gas business in general.

The volatility in the global prices of oil, natural gas and petroleum products significantly affects the Company’s operating results.

The most significant variables affecting the Company’s results of operations are the sales prices for crude oil, natural gas and refined products that it produces. West Texas Intermediate (WTI) crude oil prices averaged about $80 per barrel in 2010, $62 per barrel in 2009 and $99 per barrel in 2008. The Company had overall record net income in 2008 due to high oil sales prices. Earnings for the exploration and production business declined in 2009 from the prior year due to lower oil prices, and then rose in 2010 with higher oil prices compared to 2009. The Company’s net income is also significantly affected by changes in the sales price of natural gas and margins on refining and marketing operations. The Company cannot predict how changes in the sales prices of oil and natural gas and changes in refining and marketing margins will affect its results of operations in future periods. Except in limited cases, the Company typically does not seek to hedge any significant portion of its exposure to the effects of changing prices of crude oil, natural gas and refined products. Certain of the Company’s crude oil production is heavy and more sour than WTI quality crude; therefore, this crude oil usually sells at a discount to WTI and other light and sweet crude oils. In addition, the sales prices for heavy and sour crude oils do not always move in relation to price changes for WTI and lighter/sweeter crude oils.

The results of exploration drilling can significantly affect the Company’s operating results.

The Company generally drills numerous wildcat wells each year which subjects its exploration and production operating results to significant exposure to dry holes expense, which have adverse effects on, and create volatility for, the Company’s net income. In 2010, significant wildcat wells were primarily drilled offshore Malaysia, Republic of the Congo and Suriname. The Company’s 2011 budget calls for wildcat drilling primarily onshore in Western Canada and Kurdistan, and in waters offshore Brunei, Republic of the Congo, Suriname and Indonesia.

Capital financing may not always be available to fund Murphy’s activities.

Murphy usually must spend and risk a significant amount of capital to find and develop reserves before revenue is generated from production. Although most capital needs are funded from operating cash flow, the timing of cash flows from operations and capital funding needs may not always coincide, and the levels of cash flow may not fully cover capital funding requirements. Therefore, the Company maintains financing arrangements with lending institutions to meet certain funding needs. The Company must periodically renew these financing arrangements based on foreseeable financing needs or as they expire. The Company’s primary bank financing facility expires in June 2012. Although not considered likely, there is the possibility that financing arrangements may not always be available at sufficient levels required to fund the Company’s activities in future periods. The Company has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through September 2012. Outstanding notes of $350 million mature in April 2012. Although not considered likely, the Company may not be able in the future to sell notes at reasonable rates in the marketplace.

Murphy has limited or virtually no control over several factors that could adversely affect the Company.

The ability of the Company to successfully manage development and operating costs is important because virtually all of the products it sells are energy commodities such as crude oil, natural gas and refined products, for which the Company has little or no influence on the sales prices or regional and worldwide consumer demand for these products. An economic slowdown in late 2008 and 2009 had a detrimental effect on the worldwide demand for these energy commodities, which effectively led to reduced prices for oil, natural gas and refined products. Lower prices for crude oil and natural gas inevitably led to lower earnings in the Company’s exploration and production operations. Murphy is a net purchaser of

 

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crude oil and other refinery feedstocks, and also purchases refined products, particularly gasoline, needed to supply its retail marketing stations. Therefore, its most significant costs are subject to volatility of prices for these commodities. The Company also often experiences pressure on its operating and capital expenditures in periods of strong crude oil, natural gas and refined product prices because an increase in exploration and production activities due to high oil and gas sales prices generally leads to higher demand for, and consequently higher costs for, goods and services in the oil and gas industry.

Many of the Company’s major oil and natural gas producing properties are operated by others. During 2010, approximately 20% of the Company’s total production was at fields operated by others, while at December 31, 2010, approximately 42% of the Company’s total proved reserves were at fields operated by others. Therefore, Murphy does not fully control all activities at certain of its significant revenue generating properties.

The operations and earnings of Murphy have been and will continue to be affected by worldwide political developments.

Many governments, including those that are members of the Organization of Petroleum Exporting Countries (OPEC), unilaterally intervene at times in the orderly market of crude oil and natural gas produced in their countries through such actions as setting prices, determining rates of production, and controlling who may buy and sell the production. As of December 31, 2010, approximately 40% of proved reserves, as defined by the U.S. Securities and Exchange Commission, were located in countries other than the U.S., Canada and the U.K. Certain of the reserves held outside these three countries could be considered to have more political risk. In addition, prices and availability of crude oil, natural gas and refined products could be influenced by political unrest and by various governmental policies to restrict or increase petroleum usage and supply. Other governmental actions that could affect Murphy’s operations and earnings include tax changes, royalty increases and regulations concerning: currency fluctuations, protection and remediation of the environment (See the caption “Environmental Matters” beginning on page 33 of this Form 10-K report for additional discussion of this risk), preferential and discriminatory awarding of oil and gas leases, restrictions on drilling and/or production, restraints and controls on imports and exports, safety, and relationships between employers and employees. Because these and other factors too numerous to list are subject to changes caused by governmental and political considerations and are often made in response to changing internal and worldwide economic conditions and to actions of other governments or specific events, it is not practical to attempt to predict the effects of such factors on Murphy’s future operations and earnings.

Murphy’s business is subject to operational hazards and risks normally associated with the exploration for and production of oil and natural gas and the refining and marketing of crude oil and petroleum products.

The Company operates in urban and remote, and often inhospitable, areas around the world. The occurrence of an event, including but not limited to acts of nature such as hurricanes, floods, earthquakes and other forms of severe weather, and mechanical equipment failures, industrial accidents, fires, explosions, acts of war and intentional terrorist attacks could result in the loss of hydrocarbons and associated revenues, environmental pollution or contamination, and personal injury, including death, for which the Company could be deemed to be liable, and which could subject the Company to substantial fines and/or claims for punitive damages.

In April 2010, a drilling accident and subsequent oil spill occurred in the Gulf of Mexico at the Macondo well owned by other companies. In May 2010, the U.S. President placed a temporary moratorium on new drilling in the Gulf of Mexico that forced the Company to defer planned exploration drilling in the Gulf of Mexico, and to renegotiate a drilling contract to move a deepwater drilling rig to Republic of the Congo. Further impacts of the accident and oil spill include added delays in deepwater Gulf of Mexico drilling activities, and additional future regulations covering offshore drilling operations, plus expected higher costs for future drilling operations and offshore insurance. The restrictions associated with drilling and similar operations in the Gulf of Mexico are expected to have an adverse affect on the Company’s, and likely many other companies’, volume of oil and natural gas production in this area.

The location of many of Murphy’s key assets causes the Company to be vulnerable to severe weather, including hurricanes and tropical storms. A number of significant oil and natural gas fields lie in offshore waters around the world. Probably the most vulnerable of the Company’s offshore fields are in the U.S. Gulf of Mexico, where severe hurricanes and tropical storms have often led to shutdowns and damages. The U.S. hurricane season runs from June through November, but the most severe storm activities usually occur in late summer, such as with Hurricanes Katrina and Rita in 2005. Additionally, the Company’s largest refinery is located about 10 miles southeast of New Orleans, Louisiana. In August 2005, Hurricane Katrina passed near the refinery causing major flooding and significant wind damage. The gradual loss of coastal wetlands in southeast Louisiana increases the risk of future flooding should storms such as Katrina recur. Other assets such as gasoline terminals and certain retail gasoline stations also lie near the Gulf of Mexico

 

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coastlines and are vulnerable to storm damages. During the repairs at Meraux following Hurricane Katrina, the refinery took steps to try to reduce the potential for damages from future storms of similar magnitude. For example, certain key equipment such as motors and pumps were raised above ground level when feasible. These steps may somewhat reduce the damages associated with high winds and flooding that could occur with a future storm similar in strength to Katrina, but the risks from such a storm are not eliminated. Although the Company also maintains insurance for such risks as described below, due to policy deductibles and possible coverage limits, weather-related risks are not fully insured.

There can be no assurance that Murphy’s insurance will be adequate to offset costs associated with certain events or that insurance coverage will continue to be available in the future on terms that justify its purchase.

Murphy maintains insurance against certain, but not all, hazards that could arise from its operations. The Company maintains liability insurance sufficient to cover its share of gross insured claim costs up to approximately $775 million per occurrence and in the annual aggregate. These policies have up to $10 million in deductibles. Generally, this insurance covers various types of claims including those related to personal injury, death, property damage, loss of use and cleanup of hazardous materials discharged into the environment due to a “sudden and accidental” event. The Company also maintains insurance coverage with an additional limit of $250 million per occurrence ($600 million for Gulf of Mexico operations not related to a named windstorm), all or part of which could be applicable to certain sudden and accidental pollution events. The occurrence of an event that is not insured or not fully insured could have a material adverse effect on the Company’s financial condition and results of operations in the future. During 2005, damages from hurricanes caused a temporary shut-down of certain U.S. oil and gas production operations as well as the Meraux, Louisiana, refinery. The Company repaired the Meraux refinery and it restarted operations in mid-2006, but the Company did not fully recover repair costs incurred at Meraux under its insurance policies. Damages incurred by the Company from 2008 hurricanes did not exceed deductible limits under the insurance policies. See Notes P and R in the consolidated financial statements for further discussion.

Lawsuits against Murphy and its subsidiaries could adversely affect its operating results.

The Company is involved in numerous lawsuits seeking cash settlements for alleged personal injuries, property damages and other business-related matters. The most significant of these matters are addressed in more detail in Item 3 beginning on page 16 of this Form 10-K report.

The Company is exposed to credit risks associated with sales of certain of its products to third parties.

Although Murphy limits its credit risk by selling its products to numerous entities worldwide, it still, at times, carries substantial credit risk from its customers. For certain oil and gas properties operated by the Company, other companies which own partial interests may not be able to meet their financial obligation to pay for their share of capital and operating costs as they come due.

The costs and funding requirements related to the Company’s retirement plans are affected by several factors.

A number of actuarial assumptions impact funding requirements for the Company’s retirement plans. The most significant of these assumptions include return on assets, long-term interest rates and mortality. If the actual results for the plans vary significantly from the actuarial assumptions used, or if laws regulating such retirement plans are changed, Murphy could be required to make significant funding payments to one or more of its retirement plans in the future and/or it could be required to record a larger liability for future obligations in its Consolidated Balance Sheet.

Item 1B. UNRESOLVED STAFF COMMENTS

The Company had no unresolved comments from the staff of the U.S. Securities and Exchange Commission as of December 31, 2010.

Item 2. PROPERTIES

Descriptions of the Company’s oil and natural gas and refining and marketing properties are included in Item 1 of this Form 10-K report beginning on page 1. Information required by the Securities Exchange Act Industry Guide No. 2 can be found in the Supplemental Oil and Gas Information section of this Annual Report on Form 10-K on pages F-44 to F-52 and in Note E—Property, Plant and Equipment beginning on page F-16.

 

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Executive Officers of the Registrant

The age at January 1, 2011, present corporate office and length of service in office of each of the Company’s executive officers are reported in the following listing. Executive officers are elected annually but may be removed from office at any time by the Board of Directors.

David M. Wood – Age 53; President and Chief Executive Officer and Director and Member of the Executive Committee since January 2009. Mr. Wood served as Executive Vice President responsible for the Company’s worldwide exploration and production operations from January 2007 through December 2008, President of Murphy Exploration & Production Company-International from March 2003 through December 2006 and Senior Vice President of Frontier Exploration & Production from April 1999 through February 2003.

Steven A. Cossé – Age 63; Executive Vice President since February 2005 and General Counsel since August 1991. Mr. Cossé was elected Senior Vice President in 1994 and Vice President in 1993. Mr. Cossé has announced his retirement as of March 1, 2011.

Roger W. Jenkins – Age 49; Executive Vice President Exploration and Production since August 2009. Mr. Jenkins has served as President of the Company’s exploration and production subsidiary since January 2009. He was Senior Vice President, North America for this subsidiary from September 2007 to December 2008, and prior to that time, held various positions, including General Manager of the Company’s exploration and production operations in Sabah, Malaysia.

Thomas McKinlay – Age 47; Executive Vice President, World Wide Downstream Operations since January 2011. Mr. McKinlay was Vice President, U.S. Manufacturing from August 2009 to January 2011. Mr. McKinlay also became President of the Company’s U.S. refining and marketing subsidiary effective January 2011 and was Vice President, Supply and Transportation of this subsidiary from April 2009 to January 2011. From August 2008 to March 2009, Mr. McKinlay was General Manager, Supply and Transportation of this U.S. subsidiary, and from January 2007 to August 2008 was Supply Director for the Company’s U.K. refining and marketing subsidiary.

Kevin G. Fitzgerald – Age 55; Senior Vice President and Chief Financial Officer since January 1, 2007. He served as Treasurer from July 2001 through December 2006 and was Director of Investor Relations from 1996 through June 2001.

Bill H. Stobaugh – Age 59; Senior Vice President since February 2005. Mr. Stobaugh joined the Company as Vice President in 1995.

Mindy K. West – Age 41; Vice President and Treasurer since January 1, 2007. Ms. West was Director of Investor Relations from July 2001 through December 2006.

John W. Eckart – Age 52; Vice President and Controller since January 1, 2007. Mr. Eckart served as Controller since March 2000.

Kelli M. Hammock – Age 39; Vice President, Administration since December 2009. Ms. Hammock was General Manager, Administration from June 2006 to November 2009.

Walter K. Compton – Age 48; Vice President, Law since February 2009 and Secretary since December 1996. Effective March 1, 2011, Mr. Compton will be promoted to Senior Vice President and General Counsel, replacing Mr. Cossé who will retire on that date.

John A. Moore – Age 43; Secretary effective March 1, 2011. Mr. Moore was Senior Attorney from 2005 to February 2011.

Item 3. LEGAL PROCEEDINGS

Litigation arising out of a June 10, 2003 fire in the Residual Oil Supercritical Extraction (ROSE) unit at the Company’s Meraux, Louisiana refinery was settled in July 2009 and memorialized via a filing in the U.S. District Court for the Eastern District of Louisiana on July 24, 2009. An arbitral tribunal heard the Company’s claim for indemnity from one of its insurers, AEGIS, in September 2009 and a decision is pending. The Company believes that insurance coverage does apply for this matter. The Company continues to believe that the ultimate resolution of the June 2003 ROSE fire litigation, including associated insurance coverage issues, will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

 

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Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of matters referred to in this item is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The Company’s Common Stock is traded on the New York Stock Exchange using “MUR” as the trading symbol. There were 2,363 stockholders of record as of December 31, 2010. Information as to high and low market prices per share and dividends per share by quarter for 2010 and 2009 are reported on page F-53 of this Form 10-K report.

SHAREHOLDER RETURN PERFORMANCE PRESENTATION

The following graph presents a comparison of cumulative five-year shareholder returns (including the reinvestment of dividends) as if a $100 investment was made on December 31, 2005 for the Company, the Standard & Poor’s 500 Stock Index (S&P 500 Index) and the NYSE Arca Oil Index. This performance information is “furnished” by the Company and is not considered as “filed” with this Form 10-K and it is not incorporated into any document that incorporates this Form 10-K by reference.

Murphy Oil Corporation

Comparison of Five-Year Cumulative Shareholder Returns

Source: Bloomberg L.P.

LOGO

 

     2005      2006      2007      2008      2009      2010  

Murphy Oil Corporation

   $ 100         96         162         86         107         149   

S&P 500 Index

     100         115         122         77         97         111   

NYSE Arca Oil Index

     100         123         165         107         121         141   

 

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Item 6. SELECTED FINANCIAL DATA

 

(Thousands of dollars except per share data)

   2010      2009      2008      2007      2006  

Results of Operations for the Year

              

Sales and other operating revenues

   $ 23,401,117         18,918,181         27,360,625         18,297,637         14,156,666   

Net cash provided by continuing operations

     3,128,558         1,865,647         2,924,436         1,673,503         906,561   

Income from continuing operations

     798,081         740,517         1,744,749         739,080         603,050   

Net income

     798,081         837,621         1,739,986         766,529         644,669   

Per Common share – diluted

              

Income from continuing operations

   $ 4.13         3.85         9.08         3.87         3.19   

Net income

     4.13         4.35         9.06         4.01         3.41   

Cash dividends per Common share

     1.05         1.00         .875         .675         .525   

Percentage return on1

              

Average stockholders’ equity

     10.3         12.5         29.1         16.8         16.8   

Average borrowed and invested capital

     9.4         10.9         24.4         13.9         14.4   

Average total assets

     5.9         7.0         15.1         8.5         9.3   

Capital Expenditures for the Year2

              

Continuing operations

              

Exploration and production

   $ 2,034,828         1,807,561         1,928,346         1,740,327         1,046,463   

Refining and marketing

     407,413         375,897         426,156         572,458         173,400   

Corporate and other

     5,899         22,967         3,235         4,146         6,383   
                                            
     2,448,140         2,206,425         2,357,737         2,316,931         1,226,246   

Discontinued operations

     —           844         6,949         40,416         36,293   
                                            
   $ 2,448,140         2,207,269         2,364,686         2,357,347         1,262,539   
                                            

Financial Condition at December 31

              

Current ratio

     1.21         1.55         1.51         1.37         1.61   

Working capital

   $ 619,783         1,194,087         958,818         777,530         795,986   

Net property, plant and equipment

     10,367,847         9,065,088         7,727,718         7,109,822         5,106,282   

Total assets

     14,233,243         12,756,359         11,149,098         10,535,849         7,483,161   

Long-term debt

     939,350         1,353,183         1,026,222         1,516,156         840,275   

Stockholders’ equity

     8,199,550         7,346,026         6,278,945         5,066,174         4,121,273   

Per share

     42.52         38.44         32.92         26.70         21.97   

Long-term debt – percent of capital employed

     10.3         15.6         14.0         23.0         16.9   

 

1

Company management uses certain measures for assessing our business results, including percentage return on average stockholders’ equity, percentage return on average borrowed and invested capital, and percentage return on average total assets. Additionally, we measure our long-term debt leverage using long-term debt as a percentage of total capital employed (long-term debt plus stockholders’ equity). We consistently disclose these financial measures because we believe our shareholders and other interested parties find such measures helpful in understanding trends and results of the Company and as a comparison of Murphy Oil to other companies in our and other industries.

Specifically, these measures were computed as follows for each year.

 

   

Percentage return on average stockholders’ equity – net income for the year (as per the consolidated statement of income) divided by a 12-month average for January to December of total stockholders’ equity.

 

   

Percentage return on average borrowed and invested capital – the sum of net income for the year (as per the consolidated statement of income) plus after-tax interest expense for the year divided by a 12-month average for January to December of the sum of total long-term debt plus total stockholders’ equity.

 

   

Percentage return on average total assets – net income for the year (as per the consolidated statement of income) divided by a 12-month average for January to December of total consolidated assets.

 

   

Long-term debt–percent of capital employed – total long-term debt at the balance sheet date (as per the consolidated balance sheet) divided by the sum of total long-term debt plus total stockholders’ equity at that date (as per the consolidated balance sheet).

These financial measures may be calculated differently than similarly titled measures that may be presented by other companies.

 

2

Capital expenditures presented here include accruals for incurred but unpaid capital activities, while property additions and dry holes in the Statements of Cash Flows are cash-based capital expenditures and do not include capital accruals and geological, geophysical and certain other exploration expenses that are not eligible for capitalization under oil and gas accounting rules.

 

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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

Murphy Oil Corporation is a worldwide oil and gas exploration and production company with refining and marketing operations in the United States and United Kingdom. A more detailed description of the Company’s significant assets can be found in Item 1 of this Form 10-K report.

Murphy generates revenue primarily by selling oil and natural gas production and refined petroleum products to customers at hundreds of locations in the United States, Canada, Malaysia, the United Kingdom and other countries. The Company’s revenue is highly affected by the prices of oil, natural gas and refined petroleum products that it sells. Also, because crude oil is purchased by the Company for refinery feedstocks, natural gas is purchased for fuel at its refineries and oil production facilities, and gasoline is purchased to supply its retail gasoline stations in the U.S. that are primarily located at Walmart Supercenters, the purchase prices for these commodities also have a significant effect on the Company’s costs. In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products, amortization of capital expenditures and expenses related to exploration and administration. Profits and generation of cash in the Company’s refining and marketing operations are dependent upon achieving adequate margins, which are determined by the sales prices for refined petroleum products less the costs of purchased refinery feedstocks and gasoline and expenses associated with manufacturing, transporting and marketing these products. Murphy also incurs certain costs for general company administration and for capital borrowed from lending institutions.

Worldwide oil and North American natural gas prices were higher in 2010 than in 2009, but these prices were significantly lower on average in 2009 than in 2008. The sales price for a barrel of West Texas Intermediate crude oil averaged $79.61 in 2010, $62.05 in 2009 and $98.90 in 2008. The NYMEX natural gas price per million British Thermal Units (MMBTU) averaged $4.38 in 2010, $3.94 in 2009 and $8.89 in 2008. Crude oil prices generally strengthened in 2010 as the worldwide economy began to show signs of recovery following the deep recession that began in 2008. WTI oil prices in 2010 averaged 28% higher than 2009. The year 2009 began with quite low demand for hydrocarbons and consequently very weak prices for oil and natural gas. Crude oil and natural gas prices rose as 2009 progressed as the slow economic recovery began. Crude oil and North American natural gas prices fell precipitously with the economic decline in late 2008. 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 68% of the total hydrocarbons produced on an energy equivalent basis (one barrel of oil equals six thousand cubic feet of natural gas) by the Company in 2010. In 2011, the percentage of hydrocarbon production represented by oil is expected to decline to about 61% due to start-up of significant natural gas production in the first quarter 2011 at the Tupper West area in British Columbia. If the prices for crude oil and natural gas should weaken in 2010 or beyond, the Company would expect this to have an unfavorable impact on operating profits for its exploration and production business. Such lower oil and gas prices could, but may not, have a favorable impact on the Company’s refining and marketing operating profits.

Results of Operations

Murphy had net income in 2010 of $798.1 million ($4.13 per diluted share) compared to net income of $837.6 million ($4.35 per diluted share) in 2009. The prior year included income from discontinued operations in Ecuador of $97.1 million ($0.50 per diluted share). Income from discontinued operations in 2009 primarily arose from a gain on disposal of all Ecuador assets in March 2009. Excluding Ecuador, income from continuing operations was $798.1 million ($4.13 per diluted share) in 2010 and $740.5 million ($3.85 per diluted share) in 2009. Income in 2010 rose for both the exploration and production (E&P) and refining and marketing (R&M) operations compared to the prior year. Earnings for the Company’s E&P operations increased in 2010 primarily due to higher sales prices and sales volumes of crude oil and natural gas. The Company’s R&M earnings were higher in 2010 primarily due to stronger margins on U.S. retail gasoline fuel sales. Earnings in 2010 were unfavorably affected compared to 2009 by higher net costs associated with Corporate activities that were not allocated to operating segments, with the higher costs primarily caused by an unfavorable variance for the effects of transactions denominated in foreign currencies.

Net income in 2009 of $837.6 million ($4.35 per diluted share) was well below net income in 2008 of $1.74 billion ($9.06 per diluted share). The large decline in 2009 net income in comparison to 2008 was attributable to lower earnings in both the E&P and R&M operations. Weaker oil and natural gas sales prices in 2009 were the primary reasons for lower earnings in the E&P business, while lower retail gasoline margins in the U.S. and weaker refining margins in the U.K. led

 

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to the earnings decline for R&M. The net cost of corporate activities not allocated to the operating segments was lower in 2009 than in 2008. Income from continuing operations, excluding results from Ecuador operations which are reported as discontinued operations, was $740.5 million ($3.85 per diluted share) in 2009 compared to $1.74 billion ($9.08 per diluted share) in 2008.

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

2010 vs. 2009 – Net income in 2010 was $798.1 million ($4.13 per diluted share) compared to $837.6 million ($4.35 per diluted share) in 2009. The 2009 results included income from discontinued operations of $97.1 million ($0.50 per diluted share). The discontinued operations income was associated with Ecuador properties sold in March 2009 and primarily arose from an after-tax gain on disposal of $103.6 million. Income from continuing operations in 2010 and 2009 were $798.1 million ($4.13 per diluted share) and $740.5 million ($3.85 per diluted share), respectively. The higher 2010 income from continuing operations compared to 2009 was caused by higher earnings in both the exploration and production (E&P) and refining and marketing (R&M) businesses, but these were partially offset by higher net costs for unallocated corporate activities.

E&P income from continuing operations improved $115.1 million in 2010, primarily due to a $10.70 per barrel higher realized sales price for crude oil in the most recent year. The 2009 results were impacted by two unusual items. First, an after-tax gain of $158.3 million in 2009 was derived from a recovery of certain deepwater Gulf of Mexico federal royalties paid in prior years. Second, an after-tax charge of $58.4 million was recorded in 2009 associated with a required one-time working interest redetermination at the Terra Nova field, offshore Eastern Canada. The 2010 E&P results were also favorably affected, but in less significant measures, by higher sales volumes for crude oil and natural gas and higher sales prices for natural gas. E&P was unfavorably affected in 2010 compared to the prior year by higher expenses for exploration, production, depreciation and administration. Income from R&M operations was $77.4 million more in 2010, with the improvement mostly attributable to slightly more than a $0.03 per gallon improvement in margins on sale of gasoline at U.S. retail marketing stations. This was partially offset by higher net losses in 2010 for U.K. R&M operations. The net costs of corporate activities were higher by $134.9 million in 2010, mostly attributable to unfavorable effects of transactions denominated in foreign currencies. To a lesser degree, the 2010 corporate net costs were unfavorably affected by lower interest income and higher expenses for interest and administration. The unfavorable variance in foreign currency transactions in 2010 was primarily attributable to a strengthening of the Malaysian ringgit versus the U.S. dollar and weakening of the British pound sterling against the U.S. dollar during the year.

Sales and other operating revenues grew $4.5 billion in 2010 compared to 2009 mostly due to higher sales prices for gasoline and other motor fuels in the current year. Additionally, higher sales prices and sales volumes for crude oil and natural gas in the E&P segment contributed to the increase in 2010 revenue. Gain on sale of assets was $2.8 million less in 2010 than 2009 because the prior year included a $3.9 million gain on sale of a small Canadian natural gas field. Interest and other operating income (loss) declined by $147.4 million in 2010 compared to 2009 mostly due to a $114.3 million unfavorable variance from the effects of transactions denominated in foreign currencies, plus nonrecurring interest income in 2009 of $42.0 million associated with a recovery of Federal royalties paid in prior years for production at certain deepwater Gulf of Mexico fields. The expense associated with crude oil and product purchases increased by $3.6 billion in 2010 compared to 2009 due to higher average costs in the current year for crude oil feedstocks at the Company’s three refineries and due to the higher costs of 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 $345.4 million higher in 2010 than 2009 due to a combination of higher oil and natural gas production costs, higher operating costs associated with the three oil refineries, and higher costs for U.S. retail gasoline station operations. Exploration expenses rose $27.1 million in 2010 compared to 2009 due to higher geophysical costs in the Gulf of Mexico and Republic of the Congo, higher amortization expense for undeveloped leases in the Eagle Ford Shale, and higher administrative office and study costs in foreign locations. Exploration costs in 2010 included lower dry hole costs in Malaysia, Australia and the U.S., which more than offset higher dry hole costs in Republic of the Congo, Suriname and the U.K. Selling and general expenses were $36.9 million higher in 2010 compared to the prior year primarily due to higher employee compensation costs. Depreciation, depletion and amortization expense rose $245.7 million in 2010 versus 2009 due to higher natural gas and crude oil sales volumes in 2010, higher E&P per-unit depreciation rates, and higher R&M depreciation that included a new ethanol production facility, more U.S. retail gasoline stations and the crude unit expansion at the Milford Haven, Wales, refinery that was completed in 2010. Impairment of properties was nil in 2010 and $5.2 million in 2009, with the prior year costs related to write-off of an underperforming natural gas field in the Gulf of Mexico. Accretion of asset retirement obligations was $5.7 million more in 2010 than 2009 primarily due to higher discounted abandonment liabilities in the current year for wells drilled in Malaysia and for synthetic oil operations at Syncrude. Expense for redetermination of working interest at the Terra Nova field was $64.9 million less in 2010 than

 

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2009 because the prior year included cumulative costs for the period of December 2004 through 2009, while 2010 costs related only to current year volumes sold by the Company prior to the effective date of the final settlement. Interest expense was $0.2 million higher in 2010 primarily due to nine months of interest in the current year on nonrecourse debt associated with the Hankinson, North Dakota, ethanol production facility, compared to three months of interest on this debt in the prior year following the October 1, 2009 acquisition date. The nonrecourse debt was paid off by the Company in September 2010. The higher nonrecourse debt interest was mostly offset by lower interest expense on outstanding general bank financing balances in 2010. Capitalized interest was $10.2 million less in 2010 than in the prior year due to interest amounts allocated to the Sarawak natural gas development in 2009 prior to start-up of operations later that year, partially offset by higher interest allocated to the Tupper West gas development in 2010. Income tax expense in 2010 was $79.5 million more than 2009 due to higher pretax earnings and a slightly higher overall effective tax rate in the current year. The consolidated effective tax rate was 43.6% in 2010 compared to 42.0% in 2009, with the rate increase in the current year caused by a larger percentage of earnings in higher tax jurisdictions in 2010 and due to higher 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 2010 or future years to reduce taxes owed. The tax rates in both 2010 and 2009 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 2010 or future years. Income from discontinued operations was $97.1 million ($0.50 per diluted share) in 2009 mostly due to an after-tax gain of $103.6 million on sale of Ecuador operations in March 2009. There was no income from discontinued operations in 2010.

2009 vs. 2008 – Net income in 2009 totaled $837.6 million ($4.35 per diluted share) compared to $1.74 billion ($9.06 per diluted share) in 2008. Earnings included discontinued operations income of $97.1 million ($0.50 per diluted share) in 2009 compared to a loss of $4.8 million ($0.02 per diluted share) in 2008. Discontinued operations were associated with the Company’s former operations in Ecuador which were sold in March 2009 for an after-tax gain of $103.6 million. Income from continuing operations amounted to $740.5 million ($3.85 per diluted share) in 2009, down from $1.74 billion ($9.08 per diluted share) in 2008. The lower earnings in 2009 from continuing operations was attributable to lower income in the exploration and production (E&P) and refining and marketing (R&M) businesses.

E&P income from continuing operations was $911.0 million lower in 2009 compared to 2008, primarily attributable to weaker realized sales prices for crude oil, which were down about $33.00 per barrel for the Company’s production. Other unfavorable impacts in 2009 included a $58.4 million charge after taxes to effect an anticipated reduction in the Company’s working interest in the Terra Nova oil field offshore Newfoundland, lower North American natural gas sales prices, gains on sale of Canadian assets in 2008 that did not repeat in 2009, and higher extraction costs for oil and gas produced in 2009. E&P results in 2009 benefited from higher volumes of oil and gas produced, lower exploration expenses and after-tax income of $158.3 million from recovery of federal royalties paid between 2003 and 2009 on certain leases in the Gulf of Mexico. Income from R&M operations was $242.1 million lower in 2009 compared to 2008, essentially attributable to two factors – weaker retail gasoline marketing margins in the U.S. and weaker refining margins in the U.K. The net cost of corporate activities was $148.8 million less in 2009 than 2008 primarily due to gains from transactions denominated in foreign currencies in 2009 compared to losses on such transactions in 2008. During 2009 the U.S. dollar generally weakened in comparison to the British pound sterling, which provided a favorable foreign currency impact to the Company’s earnings. Additionally, 2009 benefited from higher interest income, including interest due to the Company through December 31, 2009 on the federal royalty refund, and lower net interest expense.

Sales and operating revenues were $8.4 billion less in 2009 than 2008 primarily due to lower prices realized on gasoline and other fuels sold by the Company. Crude oil and natural gas sales prices were also lower in 2009 than 2008. But these lower prices were partially offset by income of $244.4 million in 2009 associated with a recovery of federal royalties previously paid by the Company on certain deepwater Gulf of Mexico properties. Gain on sale of assets classified in continuing operations was $130.0 million less in 2009 than 2008 principally due to significant gains on two assets sold in Canada in 2008 – Berkana Energy and the Lloydminster properties. Interest and other income in 2009 was $152.5 million higher than 2008 due to a combination of more favorable income effects from transactions denominated in foreign currencies and interest income on the recovery of federal royalties. Crude oil and product purchases expense was $7.1 billion less in 2009 than 2008 due mostly to the lower cost of gasoline purchased for resale in the U.S. retail marketing operations. Operating expenses in 2009 were $35.6 million less than 2008 mostly due to lower natural gas and other power costs in 2009 at synthetic oil operations in Canada and at the Company’s three refineries. Exploration expense in 2009 was $79.2 million below 2008 primarily due to less spending on geophysical data in the U.S., Canada and Malaysia, and less amortization expense for undeveloped lease costs in the Tupper area in Western Canada. Selling and general expenses rose $13.8 million in 2009 compared to 2008 primarily due to a combination of higher costs for employee

 

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compensation and professional services. Depreciation, depletion and amortization expense was up $251.8 million in 2009 mostly due to higher oil and natural gas production volumes and higher depreciation rates per barrel of oil equivalents produced, with the higher costs mostly caused by new fields that came on stream in 2009. Impairment of long-lived assets of $5.2 million in 2009 was attributable to write-off of the remaining net book value for one underperforming natural gas field in the Gulf of Mexico. Accretion of asset retirement obligations increased $1.7 million in 2009 primarily due to future abandonment costs to be incurred on oil and gas wells drilled in Malaysia in 2009. A charge of $83.5 million was recorded in 2009 to reflect the estimated cash settlement to be paid on an anticipated reduction in the Company’s working interest in the Terra Nova field from the present 12.0% to about 10.5% retroactive to approximately December 2004. This redetermination process at Terra Nova was essentially completed in 2010. Interest expense in 2009 was $20.6 million less than 2008 primarily due to lower interest rates charged on certain bank loans during 2009. Interest capitalized to oil and gas development projects in 2009 was $2.8 million below the 2008 level due to commencement of production at the Thunder Hawk and Azurite oil fields in the third quarter 2009. Income tax expense was $537.0 million less in 2009 than 2008 primarily due to lower pretax income in 2009. The effective tax rate on a consolidated basis increased from 38.1% in 2008 to 42.0% in 2009 due to a larger percentage of earnings in higher tax jurisdictions in 2009 and due to higher exploration and other expenses in foreign jurisdictions where no income tax benefit can presently be recognized due to no assurance that these expenses would be realized in 2009 or future years to reduce taxes owed. The tax rates in both 2009 and 2008 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 exceed the U.S. federal tax rate, and certain exploration and other expenses in foreign taxing jurisdictions for which no income tax benefit is currently being recognized because of the Company’s uncertain ability to obtain tax benefits for these costs in 2009 or future years. Income from discontinued operations was $101.9 million higher in 2009 than 2008 mostly due to an after-tax gain of $103.6 million on sale of Ecuador operations in March 2009.

Segment Results – In the following table, the Company’s results of operations for the three years ended December 31, 2010, 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)

   2010     2009     2008  

Exploration and production – continuing operations

      

United States

   $ 72.7        178.0        156.6   

Canada

     213.8        64.8        588.7   

Malaysia

     659.4        561.9        865.3   

United Kingdom

     30.5        12.6        73.8   

Republic of the Congo

     (77.2     (20.6     (1.1

Other

     (92.3     (104.9     (80.5
                        
     806.9        691.8        1,602.8   
                        

Refining and marketing

      

United States Manufacturing

     28.4        31.2        (39.8

United States Marketing

     155.4        61.0        267.7   

United Kingdom

     (34.7     (20.5     85.9   
                        
     149.1        71.7        313.8   
                        

Corporate and other

     (157.9     (23.0     (171.8
                        

Income from continuing operations

     798.1        740.5        1,744.8   

Income (loss) from discontinued operations

     —          97.1        (4.8
                        

Net income

   $ 798.1        837.6        1,740.0   
                        

Exploration and Production – Earnings from exploration and production (E&P) continuing operations were $806.9 million in 2010, $691.8 million in 2009 and $1.60 billion in 2008.

Income from E&P continuing operations in 2010 was $115.1 million more than in 2009. The increase was primarily attributable to higher sales prices for crude oil and other liquid hydrocarbons produced by the Company. The Company’s average realized sales price for crude oil, condensate and gas liquids in 2010 increased $10.70 per barrel over 2009. The Company’s average natural gas sales prices in North American and Sarawak Malaysia were also higher in 2010 than 2009. E&P income in 2009 included a $158.3 million after-tax one-time benefit from recovery of previously paid federal royalties associated with certain fields in the deep waters of the Gulf of Mexico. Although both 2010 and 2009 had charges associated with a redetermination of working interest at the Terra Nova field offshore Eastern Canada, 2009 charges were higher by $64.9 million due to that year including estimated costs to settle the period from December 2004 to 2009, while 2010 included only costs for the current year. The one-time redetermination process was essentially

 

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completed in 2010 and reduced the Company’s working interest at Terra Nova from the original 12.0% to 10.475%. Earnings in 2010 benefited from higher crude oil and natural sales volumes. Crude oil and liquids sales volumes increased 2% in 2010 while natural gas sales volumes rose 91%. The higher hydrocarbon sales volumes in 2010 led to higher expenses for production and depreciation of $225.0 million and $229.2 million, respectively. The 2010 year also had higher exploration expenses of $27.1 million compared to 2009, essentially due to higher expenses related to geophysical activities, undeveloped lease amortization and administration, which were somewhat offset by lower expenses for dry holes. Crude oil sales volumes increased in 2010 in the U.S. due to a full year of production at the Thunder Hawk field in the Gulf of Mexico; this field started producing in July 2009. Heavy oil sales volumes in Canada were lower in 2010 than 2009 due to lower gross production and a higher royalty rate in the Seal area of Western Canada. Sales volumes in 2010 offshore Canada were below 2009 levels mostly due to lower gross production at the Terra Nova field and a higher royalty rate at the Hibernia field. Synthetic oil sales at Syncrude increased in 2010 due to higher gross production compared to 2009. Sales volumes for crude oil produced in Malaysia were lower in 2010 due to less production at the Kikeh field offshore Sabah. Crude oil liquids sold in the U.K. rose in 2010 due to making up for undersold inventory barrels produced in 2009 at the Schiehallion field. Crude oil sales increased in 2010 in Republic of the Congo due to a full year of production at the Azurite field following production start-up in August 2009. Natural gas sales volumes in 2010 increased significantly compared to the prior year due to a full year of production and higher daily sales volumes at gas fields which started up in 2009 offshore Sarawak Malaysia, as well as higher sales volumes at the Tupper area in Western Canada.

E&P income from continuing operations in 2009 was $911.0 million less than in 2008 primarily due to significantly lower realized sales prices for the Company’s crude oil production in 2009. The 2009 period was also unfavorably affected by several other factors, including lower North American natural gas sales prices, higher production and depreciation expenses, a $58.4 million after-tax charge for an anticipated reduction of its working interest in the Terra Nova field, and higher gains on asset sales in 2008 compared to 2009. The 2009 year benefited from higher oil and natural gas sales volumes, lower exploration expense and after-tax income of $158.3 million from recovery of previously paid federal royalties on production from certain deepwater Gulf of Mexico properties. Crude oil, condensate and gas liquids sales volumes from continuing operations were 8% higher in 2009 compared to 2008, compared to an increase in oil production volumes of 18% in 2009. Oil sales volumes did not rise as much as oil production volumes during 2009 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 2009 due to an increase in the volume of unsold barrels at the field at year-end and a higher percentage of such unsold inventory barrels at the field being attributable to the Company’s account. During 2008, Kikeh sales volumes exceeded production, which effectively reduced the Company’s unsold inventory balance from year-end 2007. Higher U.S. crude oil sales volume in 2009 was primarily attributable to a partial year of production at the Gulf of Mexico Thunder Hawk field, which started up in July 2009, and less downtime in the Gulf of Mexico for hurricanes. Lower crude oil sales volumes in Canada in 2009 were mostly attributable to the sale of the Lloydminster heavy oil field in early 2008 and production declines at the maturing Hibernia and Terra Nova fields. Lower crude oil sales volume in the U.K. in 2009 was primarily due to no sale at the Schiehallion field during the year, as damage to sales equipment at the production facility caused the scheduled oil sale in December 2009 to be deferred until 2010. Crude oil sales volumes at Kikeh in 2009 rose compared to 2008 due to higher annual production. Natural gas sales volumes increased 237% in 2009 and the improvement was partially attributable to higher gas volumes produced during 2009 in the Gulf of Mexico, the Tupper area in Western Canada and at Kikeh, and partially due to new production at the Sarawak gas fields offshore Malaysia following start-up in September 2009. The Company’s realized crude oil sales prices averaged 37% less in 2009 than 2008 and North American natural gas sales prices averaged 63% below 2008 levels.

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-49 and F-50 of this Form 10-K report. Average daily production and sales rates and weighted average sales prices are shown on page 5 of the 2010 Annual Report.

 

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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)

   2010      2009      2008  

United States

        

Oil and gas liquids

   $ 557.6         374.8         374.0   

Natural gas

     87.0         80.6         162.1   

Canada

        

Conventional oil and gas liquids

     388.6         365.6         775.8   

Synthetic oil

     378.6         288.5         459.6   

Natural gas

     132.1         68.6         5.5   

Malaysia

        

Oil and gas liquids

     1,531.1         1,478.4         1,985.6   

Natural gas

     307.1         45.4         0.1   

United Kingdom

        

Oil and gas liquids

     118.8         54.7         189.4   

Natural gas

     14.1         6.4         25.8   

Republic of the Congo – oil

     156.7         24.5         —     
                          

Total oil and gas revenues

   $ 3,671.7         2,787.5         3,977.9   
                          

The Company’s total crude oil, condensate and natural gas liquids production from continuing operations, which excludes discontinued operations in Ecuador sold in March 2009, averaged 126,927 barrels per day in 2010, 130,522 barrels per day in 2009 and 110,842 barrels per day in 2008.

United States crude oil production averaged 20,114 barrels per day in 2010, up from 17,053 barrels per day in 2009. The U.S. increase was primarily attributable to a full year of oil production at the Thunder Hawk field that started up in July 2009 in the Gulf of Mexico. Heavy oil production in Western Canada declined from 6,813 barrels per day in 2009 to 5,988 barrels per day in 2010 due to a combination of lower gross production in the Seal area plus a higher royalty rate there due to higher sales prices in 2010. Crude oil production offshore Canada fell from 12,357 barrels per day in 2009 to 11,497 barrels per day in 2010 essentially due to lower production levels at Terra Nova caused by field decline and a higher royalty rate at Hibernia. Synthetic oil production of 13,273 barrels per day in 2010 exceeded 2009 volumes of 12,855 per day due to less downtime for maintenance in the current year. Crude oil and liquids production in Malaysia averaged 66,897 barrels per day in 2010, down from 76,322 barrels per day in 2009, with the decrease mainly due to downtime in the current year at Kikeh for well maintenance and installation of drilling equipment on the production facility. Crude oil production in the U.K. in 2010 was about flat with 2009 as higher production volumes at Schiehallion almost offset lower volumes due to well decline at Mungo/Monan. Oil production in Republic of the Congo rose to 5,820 barrels per day in 2010 after averaging 1,743 barrels per day for all of 2009; the Azurite field came on production in August 2009.

Oil production in the U.S. increased from 10,668 barrels per day in 2008 to 17,053 barrels per day in 2009 with the increase mostly caused by start-up of the Thunder Hawk field in July 2009 and higher production at the Medusa and Front Runner fields in 2009. Production of heavy oil in the Western Canada Sedimentary Basin was 6,813 barrels per day in 2009, down from 8,484 barrels per day in 2008, primarily due to the sale of the Lloydminster property in early 2008 and due to decline at properties operated by a third party in the Seal area. Oil production offshore Canada fell from 16,826 barrels per day in 2008 to 12,357 barrels per day in 2009 due to field decline at Terra Nova and field decline and a higher net profit royalty rate at Hibernia. Synthetic oil operations at Syncrude had net production of 12,855 barrels per day in 2009, up from 12,546 barrels per day in 2008, with the increase caused by a lower royalty rate in 2009 due to sales prices significantly below those of the prior year. Oil production in Malaysia increased from 57,403 barrels per day in 2008 to 76,322 barrels per day in 2009, with the increase primarily due to higher production at the Kikeh field, which recorded peak production levels during 2009. Oil production in Malaysia was also favorably affected in 2009 by condensate produced at the Sarawak gas fields that started up in September 2009 and higher net oil production at the West Patricia field. A higher portion of production at West Patricia was allocated to the Company’s account in 2009 as costs incurred for development of Sarawak gas fields increased the level of West Patricia oil used to recover costs under the production sharing contract for Blocks SK 309 and SK 311. Oil production in the U.K. was 3,361 barrels per day in 2009, down from 4,869 barrels per day in 2008, with the decline primarily due to more downtime at the Schiehallion field, mostly due to a damaged export hose that required production to be shut-in for nearly all of the fourth quarter. The Azurite field offshore Republic of the Congo came on production in August 2009 and averaged 1,743 barrels per day for the full year of 2009. The Company sold its interest in Block 16 and other areas in Ecuador in March 2009 and has accounted for Ecuador as discontinued operations. Oil production in Ecuador, excluded from the totals for continuing operations, averaged 1,317 barrels per day in 2009 and 7,412 barrels per day in 2008.

 

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Worldwide sales of natural gas were 356.8 million cubic feet (MMCF) per day in 2010, 187.3 MMCF per day in 2009 and 55.5 MMCF per day in 2008.

Natural gas sales volumes in the U.S. were 53.0 MMCF per day in 2010, down from 2009 production of 54.2 MMCF per day as higher production at Thunder Hawk in the Gulf of Mexico and the Eagle Ford Shale area did not fully offset declines at fields onshore South Louisiana and at other fields in the Gulf of Mexico. Natural gas volumes in Western Canada increased from 54.9 MMCF per day in 2009 to 85.6 MMCF per day in 2010 essentially due to continued ramp-up of Tupper area production during the just completed year. Natural gas sales volumes in Malaysia increased in 2010 for both the Sarawak and Sabah offshore areas. Sarawak production rose to 154.5 MMCF per day in 2010 following volumes of 28.1 MMCF per day in 2009. Sarawak gas production began in September 2009 and as such was on production for all of 2010 versus four months in 2009. The Company also continued ramp-up of new wells at Sarawak gas fields during the current year. Gas sales at the Kikeh field averaged 58.2 MMCF per day in 2010, up from 46.6 MMCF per day the prior year. Natural gas sales volumes in the U.K. increased from 3.5 MMCF per day in 2009 to 5.5 MMCF per day in 2010 as gas volumes rose at both the Mungo/Monan and Amethyst fields during the current year.

Natural gas production in the U.S. averaged 54.2 MMCF per day in 2009, compared to 45.8 MMCF per day in 2008. The higher volume in 2009 was primarily attributable to the Mondo NW field that reached peak production during 2009, start-up of the Thunder Hawk field in July 2009 and less downtime in the Gulf of Mexico due to hurricanes. Natural gas production in Canada rose from 1.9 MMCF per day in 2008 to 54.9 MMCF per day in 2009 due to ramp-up of Tupper area production in Western Canada. Tupper started up in December 2008. Natural gas production in Malaysia also rose significantly in 2009 as the Sarawak gas development started up in September 2009 and Kikeh gas production, which started up in December 2008, was onstream for a full year in 2009. Natural gas production during 2009 at Sarawak and Kikeh averaged 28.1 MMCF per day and 46.6 MMCF per day, respectively. Natural gas production in the U.K. fell from 6.4 MMCF per day in 2008 to 3.5 MMCF per day in 2009 primarily due to the Amethyst field being shut-in for the first four months of 2009 for equipment repairs.

The Company’s average worldwide realized sales price for crude oil, condensate and gas liquids from continuing operations was $67.11 per barrel in 2010, $56.41 per barrel in 2009 and $89.16 per barrel in 2008.

The average realized crude oil sales price increased 19% in 2010 compared to 2009. The higher price for 2010 was slightly below the 28% increase in West Texas Intermediate (WTI) sales prices between the years. Other benchmark oil prices used for sale of Company crude oil did not increase at the same rate as WTI. The increase in the sales price for APPI Tapis based crude oil during 2010 did not keep pace with the increase in the WTI price due to differences in market conditions in Asia versus the U.S. During most of 2010, the Company sold its Kikeh crude oil based on the APPI Tapis benchmark price. In late 2010, the Company began to sell its Kikeh crude oil based on a Brent crude oil benchmark. Compared to 2009, the Company’s average 2010 crude oil sales prices rose 27% in the U.S. to average $76.31 per barrel; heavy oil sales prices in Canada rose 23% to an average of $49.89 per barrel; offshore Canada oil sold at $76.87 per barrel, an increase of 32%; Canadian synthetic crude oil sold for 27% more and averaged $77.90 per barrel; crude oil produced in Malaysia increased 10% to an average price of $60.97 per barrel; U.K. crude oil prices increased 27% to $77.95 per barrel; and crude oil sold in Republic of the Congo increased only 8% to $74.87 per barrel as the only sale in 2009 was near the end of the year when prices were above the 2009 average.

The decline in the Company’s average realized oil sales price of 37% in 2009 compared to 2008 matched the decline in the average price of West Texas Intermediate (WTI) crude oil during 2009. Crude oil prices began to weaken in late 2008 as the economic downturn worsened. Crude oil prices started 2009 at low levels due to a weakening worldwide demand for energy, but improved as the year progressed. Compared to 2008, the Company’s average 2009 crude oil sales prices fell 37% in the U.S. to $60.08 per barrel; heavy oil prices in Canada fell 31% to $40.45 per barrel; offshore Canada oil was sold for 40% less and averaged $58.19 per barrel; synthetic crude oil sold for 39% less at $61.49 per barrel; crude oil in Malaysia was down 37% and averaged $55.51 per barrel; and U.K. crude oil production sold for 32% less at $61.31 per barrel.

Virtually all natural gas prices showed improvements in 2010 compared to 2009. The prices for natural gas generally rose in the latest year in sympathy with the increase in average crude oil prices during the same period. The Company’s average sales prices for natural gas in North America increased 22% to $4.34 per MCF in 2010. Natural gas produced offshore Sarawak sold for 31% more in 2010 than in 2009 and averaged $5.31 per MCF. Natural gas produced in the U.K. sold at an average of $7.01 per MCF in 2010, a 39% increase from 2009.

 

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The Company’s natural gas sales prices fell significantly in 2009 compared to 2008 as weaker demand for energy led to an oversupply of natural gas inventories. The Company’s average realized North American natural gas sales prices were $3.57 per thousand cubic feet (MCF) in 2009, a decline of 63% from the $9.54 per MCF realized in 2008. In the U.K. the average sales price fell from $10.98 per MCF in 2008 to $5.04 per MCF in 2009. Natural gas produced in 2009 offshore Sarawak was sold at an average price of $4.05 per MCF during the year.

Based on 2010 sales volumes and deducting taxes at marginal rates, each $1.00 per barrel and $0.10 per MCF fluctuation in prices would have affected 2010 earnings from exploration and production continuing operations by $30.0 million and $8.4 million, respectively. The effect of these price fluctuations on consolidated net income cannot be measured precisely because operating results of the Company’s refining and marketing segments could be affected differently.

Production expenses from continuing operations were $879.5 million in 2010, $654.5 million in 2009 and $611.5 million in 2008. These amounts are shown by major operating area on pages F-49 and F-50 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)

   2010      2009      2008  

United States

   $ 12.46         10.62         10.01   

Canada

        

Excluding synthetic oil

     8.45         9.44         9.44   

Synthetic oil

     42.61         36.64         41.08   

Malaysia

     9.31         8.00         10.31   

United Kingdom

     14.46         17.97         13.21   

Republic of the Congo

     31.30         43.51         —     

Worldwide – excluding synthetic oil

     10.51         9.21         10.24   

Production expense per equivalent barrel in the U.S. increased in 2010 compared to 2009 due to a higher proportion of production in the later year coming from the higher-cost Thunder Hawk field in the Gulf of Mexico. Cost per barrel for Canada conventional oil and gas operations, excluding synthetic oil, was lower in 2010 than 2009 due to a larger portion of total hydrocarbons produced coming from the Tupper gas area, but this was partially offset by higher unit costs for offshore operations at Hibernia and Terra Nova. The increase in production costs per barrel for synthetic oil operations in 2010 compared to 2009 was caused by higher maintenance and natural gas costs in the current year. Production expense in Malaysia rose in 2010 compared to 2009 as higher well maintenance and workover costs at Kikeh were only partially offset by a higher proportion of lower-cost natural gas produced at fields offshore Sarawak. Production expense in 2010 in the U.K. on a per-unit basis was lower than 2009 due to less repair costs at Schiehallion and higher natural gas production at Amethyst. Per-unit production expense in 2010 in Republic of the Congo was less than in 2009 due to higher production levels associated with ramp-up of the field, which came onstream in August 2009.

Costs per barrel in the U.S. increased in 2009 compared to 2008 due to start-up of the Thunder Hawk field in July 2009. The per-unit cost for Canadian conventional oil and gas operations was flat in 2009 compared to 2008 as the benefit of a full year of natural gas production at Tupper was offset by lower production volumes without a comparable reduction in costs at Hibernia and Terra Nova. Lower cost per barrel in 2009 compared to 2008 at Canadian synthetic oil operations was mostly caused by lower natural gas fuel costs. Production cost per unit in Malaysia was lower in 2009 compared to 2008 due to higher oil production at Kikeh, and new natural gas production offshore Sarawak and higher natural gas production at Kikeh that collectively altered the production mix toward lower cost natural gas in 2009. Higher per-barrel production expense in the U.K. in 2009 compared to 2008 was primarily attributable to lower production levels at the Schiehallion and Amethyst fields, both of which were offline for repairs for a portion of 2009.

 

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Exploration expenses from continuing operations for each of the last three years are shown in total in the following table, and amounts are reported by major operating area on pages F-49 and F-50 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)

   2010      2009      2008  

Dry holes

   $ 90.1         125.3         129.5   

Geological and geophysical

     65.1         40.5         85.2   

Other

     29.1         16.2         17.7   
                          
     184.3         182.0         232.4   

Undeveloped lease amortization

     108.0         83.2         112.0   
                          

Total exploration expenses

   $ 292.3         265.2         344.4   
                          

Dry hole expense was $35.2 million lower in 2010 than in 2009 despite a 50% increase in spending for exploratory drilling. Dry hole expense in the U.S. was lower in the current year mostly due to deferral of planned Gulf of Mexico drilling due to the moratorium imposed by the Federal government following the April 2010 blowout and oil spill at the Macondo well owned by other companies. Malaysian operations had lower dry hole expense in 2010 due to more successful exploratory drilling results and favorable adjustments to final costs on prior-year wells. Dry holes in the U.K. in 2010 primarily related to a decision to expense a well drilled in 2008 for which studies in 2010 indicated a lack of economical development options based on current pricing levels. Dry hole expense in Republic of the Congo was higher in 2010 than 2009 due to drilling more unsuccessful wells in the MPS block in the current year. Dry hole expense in 2010 in other foreign areas was less than in 2009 primarily due to an unsuccessful well offshore Australia in the prior year. Geological and geophysical (G&G) expenses were $24.6 million higher in 2010 than 2009. Areas of higher spending on seismic in the 2010 year included the Eagle Ford Shale area of South Texas, the MPN and MPS blocks offshore Republic of the Congo and offshore Malaysia. These higher G&G costs in 2010 were somewhat offset by lower spending in the Tupper area of Western Canada and offshore Suriname. Other exploration costs in 2010 were $12.9 million above 2009 levels primarily due to higher administrative costs for operations in Suriname, Indonesia and Australia in the current year. Undeveloped leasehold amortization expense rose $24.8 million in 2010 compared to 2009, primarily due to higher amortization associated with lease acquisition costs in the Eagle Ford Shale area of South Texas, partially offset by less amortization expense in 2010 following sanction of development at the Tupper West property in August 2009.

Dry hole expense was $4.2 million lower in 2009 than 2008 due to more successful exploratory drilling results during a year with higher drilling capital expended. During 2009, lower dry hole costs in Malaysia and the U.S. was somewhat offset by higher costs in Australia and Republic of the Congo. G&G expenses were $44.7 million lower in 2009 compared to 2008. The reduction in G&G in 2009 was attributable to less spending on seismic in the Gulf of Mexico, the Tupper area in Western Canada, and offshore Sabah in Malaysia, but 2009 included higher spending for seismic covering the Semai II concession, offshore Indonesia. Other exploration costs were $1.5 million lower in 2009 compared to 2008 mostly due to less office costs allocable to Republic of the Congo exploration activities in the current year. Undeveloped leasehold amortization expense was $28.8 million lower in 2009 compared to 2008 mostly due to lower amortization for Tupper and Tupper West area leases in Western Canada, but partially offset by higher amortization costs for Eagle Ford Shale leases in South Texas in 2009.

An impairment charge of $5.2 million was recorded in 2009 to write-off the remaining costs of a poorly performing natural gas field in the Gulf of Mexico.

Depreciation, depletion and amortization expense for exploration and production continuing operations totaled $1,005.0 million in 2010, $775.8 million in 2009 and $527.8 million in 2008. The $229.2 million increase in 2010 was primarily caused by higher overall volumes of oil and natural gas sold during the current year. Additionally, a higher proportion of 2010 production was derived from fields brought onstream in recent years under a higher-cost development environment. The $248.0 million increase in 2009 compared to 2008 was primarily attributable to a combination of higher overall hydrocarbon production levels and start-up of new fields in the Gulf of Mexico, Western Canada and Republic of the Congo that had higher per-unit depreciation rates than older fields already on production.

The exploration and production business recorded expenses of $31.1 million in 2010, $25.5 million in 2009 and $23.5 million in 2008 for accretion on discounted abandonment liabilities. Because the abandonment liability is carried on the balance sheet at a discounted fair value, accretion must be recorded annually so that the liability will be recorded at full value at the projected time of abandonment. The $5.6 million increase in accretion expense in 2010 compared to 2009 was due to additional wells drilled during the latest year in several geographical areas and higher estimated abandonment costs for offshore operations in Malaysia and synthetic oil operations in Western Canada. The $2.0 million increase in accretion costs in 2009 compared to 2008 was mostly attributable to additional wells drilled in 2009 at the Kikeh and Sarawak fields, offshore Malaysia.

 

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The effective income tax rate for exploration and production continuing operations was 41.7% in 2010, 40.8% in 2009 and 37.4% in 2008. The effective tax rate was slightly higher in 2010 than 2009 mostly due to tax barrels owed the government of Republic of the Congo under the production sharing agreement covering the Azurite field. More tax barrels were owed the government due to higher Azurite production levels in 2010. The effective tax rate was higher in 2009 than 2008 due to both higher expenses in foreign tax jurisdictions where no tax benefit can be currently recognized due to lack of sufficient revenue to realize a current benefit and a higher percentage of profits in Malaysia where the effective tax rate of 38% is higher than the effective rates in the U.S. and Canada. 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 activities in areas where current tax benefits cannot be recorded by the Company. Tax jurisdictions with no current tax benefit on expenses primarily include non-revenue generating areas in Malaysia, Suriname, Australia and Indonesia. Each main exploration area in Malaysia is currently considered a distinct taxable entity and expenses in certain areas may not be used to offset revenues generated in other areas. No tax benefits have thus far been recognized for costs incurred for Blocks H and P, offshore Sabah, and Blocks PM 311/312, offshore Peninsula Malaysia.

At December 31, 2010, 10.8 million barrels of the Company’s U.S. proved oil reserves and 23.8 billion cubic feet of the U.S. proved natural gas reserves were undeveloped. More than 70% of the total U.S. undeveloped reserves (on a barrel of oil equivalent basis) are associated with the Company’s various deepwater Gulf of Mexico fields. Further drilling, facility construction and well workovers are required to move undeveloped reserves to developed. In the Western Canadian Sedimentary basin, total proved undeveloped natural gas reserves totaled 116.8 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, all oil reserves of 14.8 million barrels for the Kakap field are undeveloped pending completion of facilities and development drilling directed by another company. Additionally, the Kikeh field had undeveloped oil reserves of 15.8 million barrels, which are subject to further development drilling before being moved to developed. Also in Malaysia, there were 133.7 billion cubic feet of undeveloped natural gas reserves at various fields offshore Sarawak at year-end 2010, which were held under this category pending completion of development drilling and facilities. On a worldwide basis, the Company spent approximately $1.27 billion in 2010, $1.34 billion in 2009 and $783 million in 2008 to develop proved reserves.

Refining and Marketing – The Company’s refining and marketing (R&M) operations generated earnings of $149.1 million in 2010, $71.7 million in 2009 and $313.8 million in 2008. The R&M earnings improvement of $77.4 million in 2010 compared to 2009 was mostly attributable to more than a $0.03 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 2010. The R&M earnings decline of $242.1 million in 2009 compared to 2008 was driven primarily by significantly weaker margins in the U.S. retail fuel marketing business and lower refining margins in the U.K.

The Company has announced its intention to sell its U.S. refineries and U.K. refining and marketing operations in 2011.

The Company’s R&M operations in the United States generated earnings of $183.8 million in 2010, $92.2 million in 2009 and $227.9 million in 2008. U.S. operations are further reported as segregated between manufacturing and marketing activities. U.S. manufacturing activities include two oil refineries and two ethanol production facilities, while U.S. marketing activities include retail and wholesale fuel marketing operations. U.S. manufacturing operations generated profits of $28.4 million in 2010 and $31.2 million in 2009, but incurred a loss of $39.8 million in 2008. The $2.8 million decline in manufacturing income in 2010 compared to 2009 was primarily caused by nonrecurring income of $32.6 million in 2009 from insurance settlements at the Meraux, Louisiana, refinery. The insurance settlements related to property damage from Hurricane Katrina in 2005 and damage caused by a refinery fire in 2003. Final insurance proceeds for Hurricane Katrina-related property damage exceeded amounts originally estimated to be recovered. Manufacturing results in 2010 benefited from higher crude oil throughputs at both U.S. refineries, which occurred despite an approximate six-week shutdown for a plant-wide turnaround at the larger Meraux refinery. Overall refining margins per barrel at the Company’s two U.S. refineries were lower, however, in 2010 than during the prior year. The Meraux refinery ran a slightly higher mix of more expensive sweet crudes in 2010 and the refinery’s product yield of higher value gasoline and distillates in 2010 was slightly below 2009 levels. The 2010 manufacturing profit included higher earnings from the Company’s ethanol production facility in Hankinson, North Dakota. The Hankinson plant, which was acquired on October 1, 2009, was in operation for the full year of 2010 compared to three months of operations in 2009. In late 2010, the Company acquired an unfinished ethanol production facility in Hereford, Texas. The Company expects to complete construction and start-up the Hereford plant near the end of the first quarter 2011.

 

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United States manufacturing results in 2009 were improved by $71.0 million compared to 2008 partially due to final insurance settlements in 2009 at the Meraux refinery for Hurricane Katrina-related property damage and a related crude oil spill and damage caused by a 2003 fire. The insurance settlements provided pretax benefits of $32.6 million during 2009. Additionally, 2009 had slightly improved refining margins for the Company’s Gulf Coast refinery and higher asphalt sales volumes and asphalt margins at the Superior, Wisconsin refinery. The Hankinson ethanol facility generated profitable operations in the fourth quarter 2009 due to the favorable spread between ethanol sales prices and corn prices.

Unit margins (sales realization less costs of crude and other feedstocks, transportation to point of sale and refinery operating and depreciation expenses) for U.S. refining operations averaged $0.23 per barrel in 2010, compared to $0.75 per barrel in 2009 and $(1.48) per barrel in 2008. Meraux refinery throughput volumes of crude oil and other feedstocks averaged 112,578 barrels per day in 2010, 109,725 barrels per day in 2009 and 103,169 barrels per day in 2008. Superior refinery throughput volumes averaged 34,641 barrels per day of crude oil and other feedstocks in 2010, compared to 32,280 barrels per day in 2009 and 26,770 barrels per day in 2008. The Meraux refinery underwent a full plant turnaround in early 2010, and both U.S. refineries were temporarily shut-down for turnaround activities during 2008.

Marketing operations in the U.S. generated earnings of $155.4 million in 2010, $61.0 million in 2009 and $267.7 million in 2008. Profits in 2010 exceeded 2009 due to more than a $0.03 per gallon improvement in margins on fuel sold in the Company’s retail marketing system. Additionally, the Company had higher profits in 2010 on sale of merchandise in this business. Total fuel sales volumes per station at Company operated sites in the U.S. averaged about 306,600 gallons per month during 2010, down 1.9% from the prior year.

United States marketing profits fell $206.7 million in 2009 compared to 2008. Fuel margins in the retail chain were hurt in 2009 by both lower demand for gasoline and diesel due to the weak economy and generally rising wholesale fuel costs caused by crude oil prices that rose gradually during the year. The large marketing profit in 2008 was caused by significant spreads between prices for wholesale and retail gasoline for a portion of that year.

United States refined product sales volumes averaged 450,100 barrels per day in 2010, compared to 432,700 barrels per day in 2009 and 427,490 barrels per day in 2008. The increases in both 2010 and 2009 were mostly attributable to more finished products produced at the U.S. refineries compared to the prior year, plus in 2010 a full year of ethanol production from the Hankinson facility acquired in October 2009, compared to three months of ethanol production in 2009. The retail marketing business built 51 stations in 2010, following additions of 23 stations in 2009. The U.S. retail marketing network included 1,099 stations at year-end 2010.

United Kingdom R&M operations incurred a loss of $34.7 million in 2010 compared to a loss of $20.5 million in 2009 and a profit of $85.9 million in 2008. The losses in 2010 and 2009 for U.K. R&M operations were primarily due to weak margins at the Company’s Milford Haven, Wales, refinery. Additionally, in 2010 the refinery underwent approximately a two-month plant-wide turnaround that reduced crude oil throughputs in the most recent year. The refining margin was hurt by weak demand for refined products in the U.K. and Western Europe during the two-year period of 2009 and 2010. The soft demand led to an industry-wide oversupply of gasoline and diesel products in the area.

Unit margins in the United Kingdom averaged $(1.47) per barrel in 2010, $(0.28) per barrel in 2009 and $3.41 per barrel in 2008. Overall refined product sales volumes in the U.K. averaged 86,657 barrels per day in 2010, down 16% compared to 2009, primarily due to downtime associated with the turnaround at the Milford Haven refinery in 2010. Sales volumes of refined products in the U.K. declined 7% to 103,774 barrels per day in 2009 compared to 2008, essentially due to lower production of finished products at the Company’s Milford Haven, Wales refinery.

Corporate – The after-tax costs of corporate activities, which include interest income, interest expense, foreign exchange gains and losses, and unallocated corporate overhead, were $157.9 million in 2010, $23.0 million in 2009 and $171.8 million in 2008.

The net cost of corporate activities rose $134.9 million in 2010 compared to 2009. The most significant variance related to the effects of foreign currency exchange, which was associated with transactions denominated in currencies other than the respective operation’s predominant functional currency. The Company had after-tax losses from foreign currency exchange of $58.1 million in 2010, while 2009 had after-tax gains of $33.3 million. The foreign currency exchange loss in 2010 was primarily associated with a stronger Malaysian ringgit compared to the U.S. dollar. This led to costs associated with higher recorded future income tax liabilities, which are required to be paid in local currency. The Malaysian operation’s functional currency is the U.S. dollar. Foreign currency exchange losses were also experienced in the U.K. during 2010 caused by a stronger U.S. dollar compared to the British pound sterling. This led to higher costs for U.S. dollar denominated liabilities owed by the Company’s U.K. refining and marketing business, which has a sterling

 

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functional currency. Additionally, 2009 benefited from interest income of $42.0 million associated with a recovery of Federal royalties previously paid on certain deepwater Gulf of Mexico oil and natural gas production. Net interest expense, after capitalization of finance-related costs to development projects, was $10.3 million higher in 2010 than 2009 mostly due to lower interest capitalized on oil and natural gas development projects during the just completed year. Corporate activities had higher administrative and depreciation expenses in 2010 than in 2009 of $14.9 million and $2.0 million, respectively. The increase in administrative expense in 2010 was primarily associated with higher employee compensation costs. Income taxes associated with corporate activities in 2010 were significantly favorable to 2009 due to higher net pretax costs in the later year.

The net cost of corporate activities in 2009 was $148.8 million lower than in 2008, primarily due to more favorable effects of foreign currency exchange. Foreign currency exchange after taxes was a gain of $33.3 million in 2009 compared to a loss after taxes of $87.8 million in 2008. The U.S. dollar generally weakened against the British pound sterling in 2009 after having gained significant ground on the U.K. currency during 2008. The weaker dollar in 2009 reduced the cost of U.S. dollar based liabilities for the sterling-functional U.K. R&M business. Foreign currency transaction effects in Canada, Malaysia and other foreign countries were generally insignificant for the full year 2009. The corporate area also benefited in 2009 from higher interest income of $10.9 million compared to 2008, principally due to $42.0 million ($27.0 million after taxes) of interest recognized on a recovery of U.S. federal royalties previously paid on certain production in the Gulf of Mexico. The interest on royalties more than offset lower interest income earned in 2009 on cash deposits and other longer-term investments as these amounts attracted much lower interest rates during 2009 compared to the prior year. Net interest expense, after capitalization of finance-related costs to development projects, was $17.8 million less in 2009 than 2008, principally due to lower interest rates charged on certain borrowings under the Company’s credit facilities. Certain of these facilities charge interest based on a spread above LIBOR rates, which were held low in 2009 due to weakness in the overall economy. Administrative and depreciation expenses associated with corporate activities were both slightly higher in 2009 compared to 2008. Income tax expense in 2009 was significantly unfavorable to 2008 in the corporate area primarily due to the aforementioned favorable pretax variances for foreign exchange, interest income and net interest expense.

Capital Expenditures

As shown in the selected financial data on page 18 of this Form 10-K report, capital expenditures, including exploration expenditures, were $2.45 billion in 2010 compared to $2.21 billion in 2009 and $2.36 billion in 2008. These amounts included capital expenditures of $0.8 million in 2009 and $6.9 million in 2008 related to discontinued operations in Ecuador. Capital expenditures included $184.3 million, $182.0 million and $232.4 million, respectively, in 2010, 2009 and 2008 for exploration costs that were expensed. Capital expenditures for exploration and production continuing operations totaled $2.03 billion in 2010, $1.81 billion in 2009 and $1.93 billion in 2008, representing 83%, 82% and 82%, respectively, of the Company’s total capital expenditures from continuing operations for these years. E&P capital expenditures in 2010 included $242.8 million for acquisition of undeveloped leases, which primarily included leases acquired in the Eagle Ford Shale area of South Texas and in the Tupper West area in Western Canada, $470.0 million for exploration activities, $1.30 billion for development projects, and $22.0 million for acquisition of proved properties in Canada. Development expenditures included $524.7 million at the Tupper and Tupper West natural gas areas in Western Canada; $46.8 million for deepwater fields in the Gulf of Mexico; $166.8 million for the Kikeh field in Malaysia; $160.4 million for natural gas and other development activities in SK Blocks 309/311; $58.1 million for development of the Kakap field in Block K, offshore Malaysia; $63.2 million for synthetic oil operations at the Syncrude project in Canada; $84.9 million for Western Canada heavy oil projects; $126.5 million for development of the Azurite field in Republic of the Congo; and $21.2 million for the Terra Nova and Hibernia oil fields, offshore Newfoundland. Exploration and production capital expenditures are shown by major operating area on page F-48 of this Form 10-K report.

Refining and marketing capital expenditures totaled $407.4 million in 2010, $375.9 million in 2009 and $426.2 million in 2008. These amounts represented 17%, 17% and 18% of capital expenditures from continuing operations of the Company in 2010, 2009 and 2008, respectively. Refining capital spending was $179.2 million in 2010 compared to $206.0 million in 2009 and $141.8 million in 2008. Refining spending in 2010 included costs to reduce benzene production and construct a new laboratory at Meraux; costs to meet compliance with ultra-low sulfur diesel and Mobile Source Air Toxic requirements at Superior; and costs to complete an expansion to increase crude oil throughput capacity at Milford Haven to 135,000 barrels per day. Refining spending in 2009 mostly included projects at Meraux for benzene reduction, a distillate hydrotreater revamp and crude oil storage expansion; a sulfur recovery project at Superior; and an ongoing crude oil capacity expansion project at Milford Haven. Refining capital in 2008 included project costs for additional sulfur recovery capacity and property acquisition and improvements at the Meraux, Louisiana, refinery, and a cogeneration energy plant at the Milford Haven, Wales, refinery. Marketing expenditures amounted to $183.2 million in 2010, $78.5

 

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million in 2009 and $284.4 million in 2008. Marketing capital expenditures in 2010 were primarily associated with building new retail fueling stations and acquiring land for new station sites in the U.S. Marketing capital expenditures in 2009 were primarily associated with new station builds and other improvements within the U.S. retail gasoline station network. Marketing capital spending in 2008 was split between station construction costs and land acquisitions costs for existing and future retail gasoline stations. The Company added 51 stations within its U.S. retail gasoline network in 2010, after adding 23 in 2009 and 52 in 2008.

The Company spent $40.0 million in 2010 to acquire an unfinished ethanol production facility in Hereford, Texas. The Hereford facility is expected to be completed and in operation near the end of the 2011 first quarter. In 2009, the Company spent $92.0 million to acquire an ethanol production facility in Hankinson, North Dakota. The Hankinson ethanol plant was financed with an $82.0 million nonrecourse loan from the seller and a cash payment of $10.0 million. The nonrecourse loan was repaid in 2010. See Note D of the consolidated financial statements for further details about these acquisitions.

Cash Flows

Operating activities – Cash provided by operating activities was $3.13 billion in 2010, $1.86 billion in 2009 and $3.04 billion in 2008. Cash provided by continuing operations in 2010 was $1.26 billion more than 2009 primarily due to a drawdown of working capital other than cash in the current year and higher income from continuing operations. The working capital reduction in 2010 included cash receipts of $286.4 million related to recovery of federal royalties and associated interest income. Income associated with the royalty recovery was recorded in 2009, but the cash proceeds were collected in early 2010. Cash provided by continuing operations in 2009 was $1.18 billion less than in 2008 primarily due to lower net income. Cash provided by operating activities was reduced by expenditures for abandonment of oil and gas properties totaling $36.5 million in 2010, $48.7 million in 2009 and $9.2 million in 2008.

Investing activities – Cash proceeds from property sales classified as continuing operations were $2.2 million in 2010, $1.6 million in 2009 and $362.0 million in 2008. The 2008 proceeds related to sales of two Canadian assets, including the Company’s interests in Berkana Energy and the Lloydminster heavy oil property, plus a sale of 35% of its working interest in the MPS block offshore Republic of the Congo. During 2009, the Company generated cash of $78.9 million from the sale of its 20% working interest in Block 16 in Ecuador. Operating results and cash flows associated with Ecuador operations have been classified as discontinued operations in the Company’s consolidated financial statements. Property additions and dry hole costs used cash of $2.32 billion in 2010, $1.98 billion in 2009 and $2.18 billion in 2008. Cash used to pay for capital expenditures was higher in 2010 compared to 2009, but was lower in 2009 compared to 2008, with these variances essentially in line with changes in capital expenditures in each year. Cash of $2.39 billion, $2.53 billion and $1.04 billion was spent in 2010, 2009 and 2008, 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 $2.55 billion in 2010, $2.17 billion in 2009 and $623.1 million in 2008. Cash of $98.9 million in 2010, $30.3 million in 2009 and $57.6 million in 2008 was used for turnarounds at refineries and Syncrude. The increase in 2010 was attributable to plant-wide turnarounds for both the Meraux and Milford Haven refineries.

Financing activities – During 2010 and 2008, the Company used available cash flow to repay $414.0 million and $492.8 million, respectively, of debt. During 2009, the Company borrowed $243.5 million under debt agreements primarily to fund a portion of the Company’s development capital expenditures. Cash proceeds from stock option exercises and employee stock purchase plans, including income tax benefits on stock options, amounted to $54.7 million in 2010, $16.9 million in 2009 and $50.0 million in 2008. In 2009, the Company paid $10.0 million to partially finance the acquisition of the Hankinson, North Dakota, ethanol plant; the remaining $82.0 million acquisition price was financed with a seller-provided nonrecourse loan. This nonrecourse loan was fully repaid in 2010. Cash used for dividends to stockholders was $201.4 million in 2010, $190.8 million in 2009 and $166.5 million in 2008. The Company raised its annualized dividend rate from $1.00 per share to $1.10 per share beginning in the third quarter of 2010. The Company had previously increased the annualized dividend rate from $0.75 per share to $1.00 per share beginning in the third quarter of 2008.

Financial Condition

Year-end working capital (total current assets less total current liabilities) totaled $619.8 million in 2010 and $1.19 billion in 2009. 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 $735.1 million below fair value at December 31, 2010. Cash and cash equivalents at the end of 2010 totaled $535.8 million compared to $301.1 million at year-end 2009.

 

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Long-term debt, including nonrecourse loans, decreased by $413.8 million during 2010 and totaled $939.4 million at year-end 2010, representing 10.3% of total capital employed. Long-term debt decreased by $327.0 million in 2009. Stockholders’ equity was $8.20 billion at the end of 2010 compared to $7.35 billion a year ago and $6.28 billion at the end of 2008. A summary of transactions in stockholders’ equity accounts is presented on page F-6 of this Form 10-K report.

Other significant changes in Murphy’s year-end 2010 balance sheet compared to 2009 included a $162.4 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 $616.6 million at year-end 2010 and $779.0 million at year-end 2009. These slightly longer-term investments were purchased in each year because of a tight supply of shorter-term securities available for purchase in Canada. A $4.0 million increase in accounts receivable in 2010 was caused by higher sales prices and volumes for crude oil and finished products sold on credit terms by the Company, mostly offset by collection in 2010 of a receivable recorded in the prior year associated with recovery of previously paid federal royalties, plus interest thereon, totaling $286.4 million. Inventory values were $28.2 million more at year-end 2010 than in 2009 mostly due to higher valued crude and refined products held in storage within downstream operations in the later year, but partially offset by less costs for unsold crude oil production held in inventory in the current year. Prepaid expenses increased $5.0 million in 2010 primarily due to higher prepaid income taxes in the U.K. Short-term deferred income tax assets were $65.5 million higher at year-end 2010 compared to 2009 due mostly to larger current temporary differences for expense deductions within downstream operations. Net property, plant and equipment increased by $1.30 billion in 2010 as a significant level of property additions during the year exceeded the additional depreciation and amortization expensed. Goodwill increased $2.2 million in 2010 due to a stronger Canadian dollar exchange rate versus the U.S. dollar. Deferred charges and other assets decreased $3.1 million mostly due to reclassification of long-term prepaid advances from this category to property, plant and equipment during 2010, but partially offset by higher turnaround costs spent and deferred in 2010 at the Meraux and Milford Haven refineries. Current maturities of long-term debt at year-end 2010 was essentially unchanged from 2009. Accounts payable increased by $698.4 million at year-end 2010 compared to 2009 primarily due to higher amounts owed for refinery crude oil purchases and for E&P drilling activities. Income taxes payable was $28.4 million lower at year-end 2010 than at the end of 2009, primarily due to less U.S. income tax liabilities owed in the current year. Other taxes payable were $41.0 million higher mostly due to more value added taxes owed by the U.K. downstream operations at year-end 2010 compared to 2009. Other accrued liabilities increased by $21.0 million in 2010 mostly due to a deposit received related to the pending sale of a natural gas storage asset in Spain and higher postemployment plan liabilities classified as a current liability at December 31, 2010. The current portion of deferred income tax liabilities increased $17.3 million in 2010 due to various short-term temporary differences for tax deductions in Canada. Noncurrent deferred income tax liabilities were $193.4 million higher at year-end 2010 mostly due to accelerated tax depreciation associated with the Company’s 2010 capital expenditures, primarily in Malaysia and Canada. The liability associated with future asset retirement obligations increased by $78.3 million mostly due to higher estimated future costs to retire assets in the Gulf of Mexico and at synthetic oil operations in Western Canada. Deferred credits and other liabilities were $16.1 million more in 2010 compared to 2009 mostly due to higher noncurrent liabilities associated with postemployment benefit plans in the current year.

Murphy had commitments for future capital projects of approximately $1.30 billion at December 31, 2010, including $678.0 million for field development and future work commitments in Malaysia, and $118.3 million for costs to develop deepwater Gulf of Mexico fields.

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, 2010, the Company had access to a long-term committed credit facility in the amount of $1.905 billion. A total of $340.0 million was borrowed under the committed credit facility at year-end 2010. 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 2012. At December 31, 2010, the Company had uncommitted bank credit lines of approximately $430.0 million, but no borrowings were outstanding under these lines. The long-term debt to capital ratio was approximately 10.3% at year-end 2010. In September 2009, 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 may use this shelf registration, if needed, in future years to raise debt or equity capital to fund operational requirements. This shelf registration expires in September 2012. Current financing arrangements are set forth more fully in Note F to the consolidated financial statements. The Company anticipates that it may be able to repay a portion of its long-term debt during 2011. This assumption is based on the anticipated sale of its three refineries and U.K. marketing assets during 2011, plus an ability to closely match its spending plans to cash inflows during the year. However, if the Company is unable to sell these downstream assets or if future oil and natural gas prices and/or refining

 

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and marketing margins weaken significantly, the Company may have to borrow under available credit facilities to fund ongoing development projects. The Company’s ratio of earnings to fixed charges was 18.0 to 1 in 2010, 16.7 to 1 in 2009 and 28.3 to 1 in 2008.

Environmental Matters

Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment. Compliance with existing and anticipated environmental regulations affects our overall cost of business. Areas affected include capital costs to construct, maintain and upgrade equipment and facilities, in concert with ongoing operating costs for environmental compliance. Anticipated and existing regulations affect our capital expenditures and earnings, and they may affect our competitive position to the extent that regulatory requirements with respect to a particular production technology may give rise to costs that our competitors might not bear. Environmental regulations have historically been subject to frequent change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of such regulations on our operations. Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject us to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result.

Murphy allocates a portion of its capital expenditure program to comply with environmental laws and regulations, and such capital expenditures were $139.3 million in 2010 and are projected to be $117.2 million in 2011.

The most significant of those laws and the corresponding regulations affecting our U.S. operations are:

 

   

The U.S. Clean Air Act, which regulates air emissions

 

   

The U.S. Clean Water Act, which regulates discharges into U.S. waters

 

   

The U.S. Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which addresses liability for hazardous substance releases

 

   

The U.S. Federal Resource Conservation and Recovery Act (RCRA), which regulates the handling and disposal of solid wastes

 

   

The U.S. Federal Oil Pollution Act of 1990 (OPA90), which addresses liability for discharges of oil into navigable waters of the United States

 

   

The U.S Safe Drinking Water Act, which regulates disposal of wastewater into underground wells

 

   

Regulations of the U.S. Department of the Interior governing offshore oil and gas operations.

These laws and their associated regulations establish limits on emissions and standards for quality of air, water and solid waste discharges. They also generally require permits for new or modified operations. Many states and foreign countries where the Company operates also have or are developing similar statutes and regulations governing air and water as well as the characteristics and composition of refined products, which in some cases impose or could impose additional and more stringent requirements. We are also subject to certain acts and regulations, including legal and administrative proceedings, governing remediation of wastes or oil spills from current and past operations, which include but may not be limited to leaks from pipelines, underground storage tanks and general environmental operations.

CERCLA commonly referred to as the Superfund Act, and comparable state statutes primarily address historic contamination and impose joint and several liability upon Potentially Responsible Parties (PRP), without regard to fault or the legality of the original act that contributed to the release of a “hazardous substance” into the environment. Cleanup of contaminated sites is the responsibility of the owners and operators of the sites that released, disposed, or arranged for the disposal of the hazardous substances found at the site. CERCLA also authorizes the U.S. Environmental Protection Agency (EPA) and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible persons. In the course of our ordinary operations, we generate waste that falls within CERCLA’s definition of a “hazardous substance.” We may be jointly and severally liable

 

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under CERCLA for all or part of the costs required to clean up sites at which such hazardous substances have been disposed of or released into the environment. CERCLA also requires reporting of releases to the environment of substances defined as hazardous or extremely hazardous and must be reported to the National Response Center, if they exceed an EPA established reportable quantity.

The EPA currently considers us to be a PRP at one Superfund site. The potential total cost to all parties to perform necessary remedial work at this site may be substantial. However, based on current negotiations and available information, we believe that we are a de minimis party as to ultimate responsibility at the Superfund site and as such, we have not recorded a liability for remedial costs. We could be required to bear a pro rata share of costs attributable to nonparticipating PRPs or could be assigned additional responsibility for remediation at this site or other Superfund sites. We believe that our share of the ultimate costs to clean-up this Superfund site will be immaterial and will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.

We currently own or lease, and have in the past owned or leased, properties at which hazardous substances have been or are being handled. Although we have used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. While some of these historical properties are in various stages of negotiation, investigation, and/or cleanup, we are investigating the extent of any such liability and the availability of applicable defenses, including state funding for remediation, and believe costs related to these sites will not have a material adverse affect on Murphy’s net income, financial condition or liquidity in a future period. Although certain environmental expenditures are likely to be recovered by us from other sources, no assurance can be given that future recoveries from these sources will occur. Therefore, we have not recorded a benefit for likely recoveries as of December 31, 2010.

RCRA and comparable state statutes govern the management and disposal of solid wastes, with the most stringent regulations applicable to treatment, storage or disposal of hazardous wastes. We generate non-hazardous solid wastes that are subject to the requirements of RCRA and comparable state statutes. Our operating sites also incur costs to handle and dispose of hazardous waste and other chemical substances. The types of waste and substances disposed of generally fall into the following categories: spent catalysts (usually hydrotreating catalysts); spent/used filter media; tank bottoms and API separator sludge; contaminated soils; laboratory and maintenance spent solvents; and industrial debris. The costs of disposing of these substances are expensed as incurred and are not expected to have a material adverse effect on net income, financial condition or liquidity in a future period. However, it is possible that additional wastes, which could include wastes currently generated during operations, will in the future be designated as “hazardous wastes.” Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. Such changes in the regulations could result in additional capital expenditures and operating expenses.

We are also involved in personal injury and property damage claims, allegedly caused by exposure to or by the release or disposal of materials manufactured or used in our operations. Under our accounting policies, an environmental liability is recorded when such an obligation is probable and the cost can be reasonably estimated. If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used. Recorded liabilities are reviewed quarterly. Actual cash expenditures often occur one or more years after a liability is recognized.

Under OPA90, owners and operators of tankers, owners and operators of onshore facilities and pipelines, and lessees or permittees of an area in which an offshore facility is located are liable for removal and cleanup costs of oil discharges into navigable waters of the United States. To the best of our knowledge, there has been no such OPA90 claims made against Murphy.

The EPA has issued several standards applicable to the formulation of motor fuels, primarily related to the level of sulfur found in highway diesel and gasoline, which are designed to reduce emissions of certain air pollutants when the fuel is used. Several states have passed similar or more stringent regulations governing the formulation of motor fuels. The EPA’s mandated requirements for low-sulfur gasoline became effective in 2008 and both of our U.S. refineries are capable of producing the required low-sulfur gasoline. Each of the U.S. refineries are also capable of producing ultra

 

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low-sulfur diesel (ULSD) as required by the EPA beginning in 2010. Under the Clean Air Act, the EPA has issued requirements pursuant to the Mobile Source Air Toxics (MSAT) regulation for the corporate annual average of benzene content in gasoline, which is not to exceed 0.62% by volume beginning January 1, 2011, with no individual facility to exceed 1.30% by July 2012. Equipment has been installed at the Meraux and Superior refineries to achieve MSTA compliance.

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 Federal Water Pollution Control Act of 1972 (FWPCA) imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters. The FWPCA imposes substantial potential liability for the costs of removal, remediation and damages. We maintain wastewater discharge permits for our facilities where required pursuant to the FWPCA and comparable state laws. We have also applied for all necessary permits to discharge storm water under such laws. We believe that compliance with existing permits and foreseeable new permit requirements will not have a material adverse effect on our net income, financial condition or liquidity in a future period.

Our U.S. operations are subject to the Federal Clean Air Act and comparable state and local statutes. We believe that our operations are in substantial compliance with these statutes in all states in which we operate. Amendments to the Federal Clean Air Act enacted in 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.

Under the EPA’s Clean Air Act authority, the National Petroleum Refinery (NPR) Initiative (Global Consent Decree) was used by the EPA to undertake at virtually all U.S. refineries an investigation of four marquee compliance areas, including: (i) New Source Review/Prevention of Significant Deterioration for fluidized catalytic cracking units, heaters and boilers; (ii) New Source Performance Standards for flares, sulfur recovery units, fuel gas combustion devices (including heaters and boilers); (iii) Leak Detection and Repair requirements; and (iv) Benzene National Emissions Standards for Hazardous Air Pollutants. Murphy began negotiations with the EPA in 2005, but was interrupted by the events of Hurricane Katrina. The states of Louisiana and Wisconsin are both parties to the NPR. Negotiations with EPA resumed in 2007 and were essentially completed in 2010. Under the Global Consent Decree, the Company agreed to pay a fine of $1.25 million and committed to capital improvements that are anticipated to cost approximately $142 million over the next eight years.

Our Meraux, Louisiana, refinery is also currently negotiating with the Louisiana Department of Environmental Quality (LDEQ) regarding three Compliance Order/Notice of Proposed Penalty (CO/NOPP) notifications regarding air and water discharges. While we are in various stages of negotiations and/or settlement, the Company has proposed a settlement offer related to these CO/NOPP negotiations and has reached agreement either independently with the State of Louisiana or as a condition of settlement of the federal Global Consent Decree, with approval of the State of Louisiana. The Company does not expect the settlement of this matter to have a material adverse effect on Company’s net income, financial condition or liquidity in a future period.

World leaders have held numerous discussions about the level of worldwide greenhouse gas emissions. As part of these discussions, the Kyoto Agreement was adopted in 1997 and was ratified by certain countries in which we operate or may operate in the future, with the United States being the primary country that has yet to ratify the agreement. While efforts were made at the Copenhagen Accord, held December 19, 2009, to strengthen the Kyoto Protocol which expires in 2012, the delegates to the 15th session of the Conference of the Parties (COP15) at Copenhagen agreed only to “take note” of the proceedings and did not ratify or agree to a successor to the Kyoto Protocol. We are unable to predict how U.S. regulations (if any) associated with the Kyoto Agreement will impact costs in future years. The European Union has adopted an Emissions Trading Scheme in response to the Kyoto Agreement in order to achieve reductions in greenhouse gas emissions. Our refining operations at Milford Haven currently have the most exposure to these requirements and may require purchase of emission allowances to maintain compliance with environmental permit requirements. These environmental expenditures are expensed as incurred.

 

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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. During 2010, U.S. federal legislation (Cap and Trade 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 to develop statewide or regional programs, each of which have or could impose mandatory reductions in greenhouse gas emissions. The impact of existing and pending climate change legislation, regulations, international treaties and accords could result in increased costs to (i) operate and maintain our facilities; (ii) install new emission controls on our facilities; and (iii) administer and manage any greenhouse gas emissions trading program. These actions could also impact the consumption of refined products, thereby affecting our refinery operations. The physical impacts of climate change present potential risks for severe weather (floods, hurricanes, tornadoes, etc.) at our Meraux, Louisiana, refinery in southern Louisiana and our 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 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.

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 climate-change related information. The Company’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. Further, in February 2009, our Board 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 our operations, products and services on the environment by implementing economically feasible projects that promote energy efficiency and use natural resources effectively.” We likewise apply this conscientious approach to the issue of climate change. As a companion to the EHS Policy, the Company’s Web site also contains a statement on climate change. Not only does this statement on climate change include our goal of reducing greenhouse gas emissions on an absolute basis while growing our upstream and certain downstream operations, the information on our Web site describes actions we have already taken to move towards that goal. While we are admittedly in the early stages of a process that will grow over time, the Company has formed an internal Climate Change Workgroup to address emerging climate change issues and improve energy efficiencies. This Climate Change Workgroup is working with the respective business units to focus on comprehensive climate change efforts aimed at preparing the company to succeed in a world challenged to reduce greenhouse gas emissions. These efforts include incorporating climate change into our planning processes, reducing our own 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. The initiatives cited above demonstrate the Company’s commitment regarding environmental issues, which are at the forefront of today’s global public policy dialogue.

Murphy is actively engaged in the legislative and regulatory process, both nationally and internationally, in response to climate change issues and to protect our competitive advantage. Additionally, Murphy participates in the Massachusetts Institute of Technology (MIT) Joint Program on the Science and Policy of Global Change.

Safety Matters

We are subject to the requirements of the Federal Occupational Safety and Health Act (OSHA) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, record-keeping requirements and monitoring of occupational exposure to regulated substances.

 

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In 2007, OSHA announced a National Emphasis Program (NEP) for inspecting all refineries in the U.S. for compliance with OSHA’s Process Safety Management (PSM) regulations. OSHA conducted an inspection of our Meraux, Louisiana refinery from July-September 2009, and on December 29, 2009, OSHA issued several compliance related citations and a proposed penalty. The matter was settled with OSHA through payment of a $63,000 penalty with all of the OSHA items abated in 2010, with concurrence from OSHA that the NEP event is now closed.

Other Matters

Oil Spill Response Plan – Each Murphy offshore facility in the Gulf of Mexico has in place an Emergency Evacuation Plan (EEP) and an Oil Spill Response Plan (OSRP). In the event of an explosion, personnel would be evacuated immediately in accordance with the EEP and the OSRP would be activated if needed. In the event of an oil spill, the OSRP would be executed as needed. The EEP is approved by U.S. Coast Guard (USCG) and the OSRP is approved by Bureau of Ocean Energy Management (formerly the Minerals Management Service). 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. We have further contracted with another company to utilize their equipment for oil containment should a well blowout occur.

Impact of inflation – General inflation was moderate during the last three years in most countries where the Company operates; however, the Company’s revenues and capital and operating costs are influenced to a larger extent by specific price changes in the oil and gas and allied industries than by changes in general inflation. Crude oil and petroleum product prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC production levels and/or attitudes of traders concerning supply and demand in the near future. Natural gas prices are affected by supply and demand, which 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 when oil and gas prices were strong. As noted earlier, oil and natural gas prices have been extremely volatile over the last several years. Oil prices were very strong in early to mid 2008, then fell precipitously in late 2008 and into early 2009, then have generally strengthened since that time. The prices for oil field goods and services generally rise in periods of higher oil prices and do not usually decline as significantly as oil and gas prices in a lower price environment. Should oil prices continue to rise 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 – The Company adopted new guidance issued by the Financial Accounting Standards Board (FASB) regarding accounting for transfers of financial assets effective January 1, 2010. This guidance makes the concept of a qualifying special-purpose entity as defined previously no longer relevant for accounting purposes. Therefore, formerly qualifying special-purpose entities must be reevaluated for consolidation by reporting entities in accordance with the applicable consolidation guidance. This adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted, effective January 1, 2010, new guidance issued by the FASB that requires a company to perform an analysis to determine whether its variable interests give it a controlling financial interest in a variable interest entity. The primary beneficiary of a variable interest entity has both the power to direct the activities of the entity that most significantly impact the entity’s economic performance and the obligation to absorb potentially significant losses of the entity or the right to receive potentially significant benefits from the entity. A company is required to make ongoing reassessments of whether it is the primary beneficiary of a variable interest entity. This guidance also amends previous guidance for determining whether an entity is considered a variable interest entity. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

 

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In July 2010, the FASB issued new accounting guidance that expands the disclosure requirements about financing receivables and the related allowance for credit losses. This guidance became effective for the Company at December 31, 2010. Because the Company has no significant financing receivables that extend beyond one year, the impact of this guidance did not have a significant effect on its consolidated financial statement disclosures.

The Company adopted new accounting guidance for noncontrolling interests in consolidated financial statements effective January 1, 2009. This guidance is applied prospectively, except for presentation and disclosure requirements which are applied retrospectively. This guidance required noncontrolling interests to be reclassified as equity, and consolidated net income and comprehensive income shall include the respective results attributable to noncontrolling interests. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted new accounting guidance covering business combinations effective January 1, 2009. The new guidance established principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquired business. It also established how to recognize and measure goodwill acquired in the business combination or a gain from a bargain purchase, if applicable. This guidance impacts the recognition and measurement of assets and liabilities in business combinations that occur beginning in 2009. Assets and liabilities that arose from business combinations that occurred prior to 2009 are not affected by this guidance. The adoption of this guidance did not have a significant effect on the Company’s financial statements for the year ended December 31, 2009. The Company is unable to predict how the application of this guidance will affect its financial statements in future periods.

The Company adopted new accounting guidance which addressed disclosures about derivative instruments and hedging activities in January 2009. This guidance expanded required disclosures regarding derivative instruments to include qualitative information about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts and gains and losses on derivative instruments, and disclosures about credit-risk related contingent features in derivative agreements. See Note L of this Form 10-K for further disclosures.

In 2009, the Company adopted new accounting guidance for determining whether instruments granted in share-based payment transactions are participating securities. This guidance specified that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings per share (EPS) calculation under the two-class method, and also required that all prior-period EPS calculations be adjusted retrospectively. The adoption of this guidance did not have a significant impact on the Company’s prior-period EPS calculations.

The Company adopted new accounting guidance addressing certain equity method investment accounting considerations in January 2009. The guidance, which has been applied prospectively, addressed how to initially measure contingent consideration for an equity method investment, how to recognize other-than-temporary impairments of an equity method investment, and how an equity method investor is to account for a share issuance by an investee. The adoption of this guidance did not have a significant impact on the Company’s consolidated financial statements.

The Company adopted new accounting guidance addressing subsequent events effective June 30, 2009. The guidance clarified the accounting for and disclosure of subsequent events that occur after the balance sheet date through the date of issuance of the applicable financial statements. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The FASB’s Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles guidance became effective for interim and annual periods ended after September 15, 2009, and it recognized the FASB Accounting Standards Codification as the single source of authoritative nongovernment U.S. generally accepted accounting principles. The codification superseded all existing accounting standards documents issued by the FASB, and established that all other accounting literature not included in the codification is considered nonauthoritative. Although the codification did not change U.S. generally accepted accounting principles, it did reorganize the principles into accounting topics using a consistent structure. The codification also included relevant U.S. Securities and Exchange Commission guidance following the same topical structure. For periods ending after September 15, 2009, all references to U.S. generally accepted accounting principles use the new topical guidelines established with the codification. Otherwise, this new standard did not have a material impact on the Company’s consolidated financial statements.

 

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The FASB has provided additional guidance regarding disclosures about postretirement benefit plan assets, including how asset investment allocation decisions are made, the fair value of each major category of plan assets, and how fair value is determined for each major asset category. This guidance was effective for the Company as of December 31, 2009. Upon adoption, no comparative disclosures were required for earlier years presented. See Note K of this Form 10-K for additional disclosures.

In December 2008, the U.S. Securities and Exchange Commission (SEC) adopted revisions to oil and natural gas reserves reporting requirements which became effective for the Company at year-end 2009. The primary changes to reserves reporting included:

 

   

A revised definition of proved reserves, including the use of unweighted average oil and natural gas prices in effect at the beginning of each month during the year to compute such reserves,

 

   

Expanding the definition of oil and gas producing activities to include non-traditional and unconventional resources, which includes the Company’s Canadian synthetic oil operations at Syncrude,

 

   

Allowing companies to voluntarily disclose probable and possible reserves in SEC filings,

 

   

Amending required proved reserve disclosures to include separate amounts for synthetic oil and gas,

 

   

Expanded disclosures of proved undeveloped reserves, including discussion of such proved undeveloped reserves five years old or more, and

 

   

Disclosure of the qualifications of the chief technical person who oversees the Company’s overall reserve process.

The Company utilized this new guidance at December 31, 2010 and 2009 to determine its proved reserves and to develop associated disclosures. The Company chose not to provide voluntary disclosures of probable and possible reserves in this Form 10-K. In January 2010, the FASB issued guidance that aligned its oil and gas reporting requirements and effective date with the SEC’s guidance described above.

The United States Congress passed the Dodd-Frank Act in 2010. Among other requirements, the law requires companies in the oil and gas industry to disclose payments made to the U.S. Federal and all foreign governments. The SEC was directed to develop the reporting requirements in accordance with the law. The SEC has issued preliminary guidance and is seeking feedback thereon from all interested parties. The preliminary rules indicated that payment disclosures would be required at a project level within the annual Form 10-K report beginning with the year ending December 31, 2012. The Company cannot predict the final disclosure requirements that will be required by the SEC.

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 U.S. Securities and Exchange Commission (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 regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether 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 that we use an unweighted average of the oil and gas prices in effect at the beginning of each month of the year for determining proved reserve quantities. These historical prices often do not approximate the

 

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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 reserve quantities. Reserve revisions inherently lead to adjustments of the Company’s depreciation rates and the timing of settlement of asset retirement obligations.

The Company’s proved reserves of oil and natural gas are presented on pages F-46 and F-47 of this Form 10-K. The positive revision in U.S. proved oil reserves in 2010 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 reserve 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 reserve revision in Malaysia in 2010 primarily related to better well performance at the Kikeh field. A positive proved oil reserve 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. A favorable oil reserve revision in 2009 in the United States was attributable to favorable performance of the Thunder Hawk and Front Runner fields and federal royalty relief for various deepwater fields. A favorable conventional oil revision in Canada in 2009 was caused by performance of the Terra Nova field and improved heavy oil pricing which added reserves in the Seal area. Due to changes in the SEC’s definition of proved oil reserves, which were first effective as of December 31, 2009, synthetic oil reserves are now included as proved oil reserves. Consequently, total synthetic oil reserves as of January 1, 2009 of 131.6 million barrels were added to total oil reserves in 2009. The positive revision to synthetic oil reserves during 2009 was attributable to lower royalties compared to a year ago. An unfavorable revision to oil reserves in Malaysia in 2009 was due to current-year drilling results for a well in the Kikeh field, along with reduced entitlements at Kikeh and West Patricia due to increased prices at year-end 2009 compared to year-end 2008. Oil reserves in the U.K. reflected an unfavorable revision in 2009 because of an anticipated reduction in life expectancy for major equipment at the Schiehallion project. An unfavorable U.S. oil revision in 2008 resulted from updated reservoir modeling of one field in the deepwater Gulf of Mexico. An unfavorable revision in Canada in 2008 was related to low heavy oil prices at year-end, but this was partially offset by a favorable impact from better field performance in 2008 at Hibernia. A favorable oil reserve revision in Malaysia in 2008 was attributable to better than anticipated drilling results and additional drilling opportunities in the main reservoir at the Kikeh field, coupled with better reservoir performance and artificial lift improvements at the West Patricia field.

Proved natural gas reserves in the U.S. had positive revisions in 2010 due to better well performance at the Thunder Hawk and Mondo fields in the Gulf of Mexico. The positive gas reserve 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 reserve revisions in the U.K. in 2010 were attributable to better well performance at all gas producing fields. In 2009, a positive U.S. gas reserve revision was caused by favorable performance of the Thunder Hawk, Front Runner and Mondo NW fields as well as federal royalty relief for various deepwater fields. In Malaysia, a combination of increased entitlements due to pricing and drilling performance at the Sarawak gas project led to positive gas revisions in 2009. Gas reserves in the U.K. were favorably revised in 2009 because of the Amethyst field gas compression project and better Mungo field performance. An unfavorable natural gas reserve revision in Malaysia in 2008 was related to entitlement adjustments under the production sharing contract for Blocks SK 309 and SK 311 and gas volumes lost due to operational delays that restricted sales volumes at the Kikeh field, offshore Sabah.

The Company cannot predict the type of oil and natural gas reserve revisions that will be required in future periods.

 

   

Successful efforts accounting – The Company utilizes the successful efforts method to account for exploration and development expenditures. Unsuccessful exploration wells are expensed and can have a significant effect on net income. Successful exploration drilling costs, all development capital expenditures and asset retirement costs are capitalized and systematically charged to expense using the units of production method based on proved developed oil and natural gas reserves as estimated by the Company’s engineers.

 

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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 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 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. There were no dry holes in 2009 or 2008 that were drilled in prior years.

 

   

Impairment of long-lived assets – The Company continually monitors its long-lived assets recorded in Property, Plant and Equipment and Goodwill in the Consolidated Balance Sheet to make sure that they are fairly presented. The Company must evaluate its properties for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable from future cash flows. Goodwill is evaluated for impairment at least annually. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the amount of oil and natural gas that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, future capital and abandonment costs, future margins on refined products produced and sold, and future inflation levels. The need to test a property for impairment can be based on several factors, including but not limited to a significant reduction in sales prices for oil and/or natural gas, unfavorable reserve revisions, expected deterioration of future refining and/or marketing margins for refined products, or other changes to contracts, environmental regulations or tax laws. All of these same factors must be considered when evaluating a property’s carrying value for possible impairment.

In making its impairment assessments involving exploration and production property and equipment, the Company must make a number of projections involving future oil and natural gas sales prices, future production volumes, and future capital and operating costs. Due to the volatility of world oil and gas markets, the actual sales prices for oil and natural gas have often been quite different from the Company’s projections. Estimates of future oil and gas production and sales volumes are based on a combination of proved and risked probable and possible reserves. Although the estimation of reserves and future production is uncertain, the Company believes that its estimates are reasonable; however, there have been cases where actual production volumes were higher or lower than projected and the timing was different than the original projection. The Company adjusts reserves and production estimates as new information becomes available. The Company generally projects future costs by using historical costs adjusted for both assumed long-term inflation rates and known or expected changes in future operations. Although the projected future costs are considered to be reasonable, at times, costs have been higher or lower than originally estimated. In assessing potential impairment involving refining and marketing assets, the Company evaluates its properties when circumstances indicate that carrying value of an asset may not be recoverable from future cash flows. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events, which include projections of future margins, future capital expenditures and future operating expenses. Future marketing or operating decisions, such as closing or selling certain assets, and future regulatory or tax changes could also impact the Company’s conclusion about potential asset impairment. Impairment expense of $5.2 million was recorded in 2009 to write-off the remaining carrying value of one underperforming natural gas field in the Gulf of Mexico. Based on an evaluation of expected future cash flows from properties at year-end 2010, 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 2010. In addition, one or a combination of factors such as lower future sales prices, lower future production, higher future costs, lower future margins on refining and marketing sales, or the actions of government authorities could lead to impairment expenses in future periods. Based on these unknown future factors as described herein, the Company cannot predict the amount or timing of impairment expenses that may be recorded in the future.

 

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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, P 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 and Suriname, 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. 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.

Based on bond yields at year-end 2010, the Company has used a discount rate of 5.66% at year-end 2010 and beyond for the primary U.S. plans. Although the Company presently assumes a return on plan assets of 6.50% for the primary U.S. plan, it periodically reconsiders the appropriateness of this and other key assumptions. The smoothing effect of current accounting regulations tends to buffer the current year’s pension expense from wide swings in liabilities and asset valuations. The Company’s normal annual retirement and postretirement plan expenses are expected to increase slightly in 2011 compared to 2010 based on the effects of a growing employee base. In 2010, the Company paid $20.7 million into various retirement plans and $3.9 million into postretirement plans. In 2011, the Company is expecting to fund payments of approximately $39.3 million into various retirement plans and $6.0 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. 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 2011 annual retirement and postretirement expenses by $6.6 million and $1.0 million, respectively, and a 0.5% decline in the assumed rate of return on plan assets would increase 2011 retirement expense by $2.1 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.

 

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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 2010 under such contractual obligations and arrangements are shown below.

 

     Amount of Obligation  

(Millions of dollars)

   Total      2011      2012-2013      2014-2015      After 2015  

Total debt including current maturities

   $ 939.4         —           689.9         0.1         249.4   

Operating leases

     983.9         166.0         288.7         239.6         289.6   

Purchase obligations

     1,944.5         1,341.7         440.8         57.4         104.6   

Other long-term liabilities

     698.6         42.2         25.6         106.9         523.9   
                                            

Total

   $ 4,566.4         1,549.9         1,445.0         404.0         1,167.5   
                                            

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.

In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide financial guarantees or letters of credit that may be drawn upon if the Company fails to perform under those contracts. The amount of commitments as of December 31, 2010 that expire in future periods is shown below.

 

     Amount of Commitment  

(Millions of dollars)

   Total      2011      2012-2013      2014-2015      After 2015  

Financial guarantees

   $ 7.8         —           —           3.8         4.0   

Letters of credit

     223.4         219.6         —           —           3.8   
                                            

Total

   $ 231.2         219.6         —           3.8         7.8   
                                            

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 2010 includes 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, a natural gas transportation contract for the Tupper area in Western Canada and a hydrogen purchase contract for the Meraux refinery. The leases call for future monthly net lease payments through 2015 at Kikeh, through 2016 at Azurite, through 2014 at Thunder Hawk and through 2012 at West Patricia. The Tupper transportation contract requires minimum monthly payments through 2018. The Meraux refinery contract to purchase hydrogen ends in 2021. The hydrogen contract requires a monthly minimum base facility charge whether or not any hydrogen is purchased. Future required minimum annual payments under these arrangements are included in the contractual obligation table shown above.

Outlook

Prices for the Company’s primary products are often quite volatile. The price for crude oil is primarily attributable to the level of demand for energy. In January 2011, West Texas Intermediate crude oil traded in a band between $86 and $92 per barrel. NYMEX natural gas traded in a band of $4.30 to $4.70 per MMBTU during this same time. U.S. refining margins in January 2011 were somewhat stronger than in late 2010, but U.S. retail marketing margins were squeezed by higher wholesale fuel costs 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 2011 was prepared during the fall of 2010 and based on this budget capital expenditures are expected to be slightly higher than 2010 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 2011 budget, but North American natural gas prices have generally trailed the budgeted prices. Based on a recent review of capital expenditure projects, capital expenditures in 2011 are projected to total approximately $2.25 billion. Of this amount, $2.0 billion or about 88%, is allocated for the exploration and production program. Geographically, E&P capital is spread approximately as follows: 23% each for the United States and Malaysia, 39% for Canada and 15% for all other areas. Spending in the

 

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U.S. is primarily associated with development and exploration programs in the Eagle Ford Shale. The Company believes that budgeted 2011 spending for exploration and development activities in the Gulf of Mexico is at risk due to the U.S. government’s delay in permitting all such activities following the Macondo incident in 2010. In Malaysia, the majority of the spending is for continued development of natural gas fields in Blocks SK 309 and SK 311 offshore Sarawak and at the Kikeh and Kakap fields in Block K. Approximately one-half of Canadian spending in 2011 will relate to natural gas development activities at the Tupper and Tupper West areas in Western Canada, with the remainder to be spent on continued development of existing oil fields. Other spending is primarily in Republic of the Congo for continued development of the Azurite offshore field and further exploration drilling in the MPS block. Refining and marketing expenditures in 2011 should be about $265 million, or 12% of the Company total, including funds for construction of additional U.S. retail gasoline stations. Capital and other expenditures will be routinely reviewed during 2011 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 2011 using operating cash flow, but will supplement funding where necessary using borrowings under available credit facilities. The Company’s 2011 budget calls for a partial pay down of long-term debt during the year, primarily based on the assumption that worldwide refining and U.K. marketing assets will be sold during 2011. If oil and/or natural gas prices weaken or refining and U.K. marketing assets are not sold, actual cash flow generated from operations or asset dispositions could be reduced such that borrowings might be required during the year to maintain funding of the Company’s ongoing development projects.

The Company currently expects production in 2011 to average between 200,000 and 210,000 barrels of oil equivalent per day. A key assumption in projecting the level of 2011 Company production is the anticipated ramp-up of natural gas production following a February 2011 start-up at the Tupper West area in Western Canada. Other key assumptions include the timing of and ramp-up of oil production from well workovers at the Kikeh field and well performance at the Azurite field offshore Republic of the Congo. In addition, continued reliability of production at significant operations such as Syncrude, Hibernia and Terra Nova and the continued demand for natural gas from our offshore Malaysia fields are necessary to achieve the anticipated 2011 production levels.

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, political and regulatory instability, and uncontrollable natural hazards. For further discussion of risk factors, see Item 1A. Risk Factors, which begins on page 12 of this Annual Report on Form 10-K. Murphy undertakes no duty to publicly update or revise any forward-looking statements.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note L to the consolidated financial statements, Murphy makes limited use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.

There were short-term commodity derivative contracts in place at December 31, 2010 to hedge the value of about 0.1 million barrels of crude oil at the Company’s refineries. Additionally, on this date the Company had open fixed-price corn purchase commitments of approximately 7.0 million bushels of corn expected to be purchased and processed at the Company’s ethanol production facility. The Company also had open derivative contracts at that date to sell 7.5 million bushels of corn at these fixed prices and buy it back at future prices in effect at the time the corn is actually purchased. A 10% increase in the respective benchmark price of these commodities would have reduced the recorded asset associated with these derivative contracts by approximately $1.6 million, while a 10% decrease would have increased the recorded asset by a similar amount. Changes in the fair value of the Company’s derivative contracts generally offset the changes in the value for an equivalent volume of these feedstocks.

There were short-term derivative foreign exchange contracts in place at December 31, 2010 to hedge the value of U.S. dollars against two foreign currencies. A 10% strengthening of the U.S. dollar against these foreign currencies would have reduced the recorded net asset associated with these contracts by approximately $37.4 million, while a 10% weakening of the U.S. dollar would have increased the recorded net asset by approximately $45.6 million. Changes in the fair value of these derivative contracts generally offset the financial statement impact of an equivalent volume of foreign currency exposures associated with other assets and/or liabilities.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Information required by this item appears on pages F-1 through F-53, which follow page 49 of this Form 10-K report.

 

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Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

Item 9A. CONTROLS AND PROCEDURES

Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by Murphy to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

Based on their evaluation, with the participation of the Company’s management, as of December 31, 2010, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

Murphy’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Management has conducted an evaluation of the effectiveness of our internal control over financial reporting based on the criteria set forth in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, management has concluded that our internal control over financial reporting was effective as of December 31, 2010. Our report is included on page F-2 of the annual report. KPMG LLP, an independent registered public accounting firm, has made an independent assessment of the effectiveness of our internal control over financial reporting as of December 31, 2010 and their report is also included on page F-2 of this annual report.

There were no changes in the Company’s internal controls over financial reporting that occurred during the fourth quarter of 2010 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B. OTHER INFORMATION

None

PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Certain information regarding executive officers of the Company is included on page 16 of this Form 10-K report. Other information required by this item is incorporated by reference to the Registrant’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 11, 2011 under the captions “Election of Directors” and “Committees.”

Murphy Oil has adopted a Code of Ethical Conduct for Executive Management, which can be found under the Corporate Governance and Responsibility tab at www.murphyoilcorp.com. Stockholders may also obtain free of charge a copy of the Code of Ethical Conduct for Executive Management by writing to the Company’s Secretary at P.O. Box 7000, El Dorado, AR 71731-7000. Any future amendments to or waivers of the Company’s Code of Ethical Conduct for Executive Management will be posted on the Company’s internet Web site.

Item 11. EXECUTIVE COMPENSATION

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 11, 2011 under the captions “Compensation Discussion and Analysis” and “Compensation of Directors,” and in various compensation schedules.

 

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Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 11, 2011 under the captions “Security Ownership of Certain Beneficial Owners,” “Security Ownership of Management,” and “Equity Compensation Plan Information.”

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 11, 2011 under the caption “Election of Directors.”

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 11, 2011 under the caption “Audit Committee Report.”

PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

 

(a)    1. Financial Statements – The consolidated financial statements of Murphy Oil Corporation and consolidated subsidiaries are located or begin on the pages of this Form 10-K report as indicated below.

 

     Page No.  

Report of Management – Consolidated Financial Statements

     F-1   

Report of Independent Registered Public Accounting Firm

     F-1   

Report of Management – Internal Control Over Financial Reporting

     F-2   

Report of Independent Registered Public Accounting Firm

     F-2   

Consolidated Statements of Income

     F-3   

Consolidated Balance Sheets

     F-4   

Consolidated Statements of Cash Flows

     F-5   

Consolidated Statements of Stockholders’ Equity

     F-6   

Consolidated Statements of Comprehensive Income

     F-7   

Notes to Consolidated Financial Statements

     F-8   

Supplemental Oil and Gas Information (unaudited)

     F-44   

Supplemental Quarterly Information (unaudited)

     F-53   

 

  2. Financial Statement Schedules

 

Schedule II – Valuation Accounts and Reserves      F-54   

All other financial statement schedules are omitted because either they are not applicable or the required information is included in the consolidated financial statements or notes thereto.

 

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3. Exhibits – The following is an index of exhibits that are hereby filed as indicated by asterisk (*), that are considered furnished rather than filed, or that are incorporated by reference. Exhibits other than those listed have been omitted since they either are not required or are not applicable.

 

Exhibit

No.

        

Incorporated by Reference to

  *3.1

   Certificate of Incorporation of Murphy Oil Corporation as amended, effective May 11, 2005   

    3.2

   By-Laws of Murphy Oil Corporation as amended effective February 3, 2010    Exhibit 3.2 of Murphy’s Form 8-K filed February 4, 2010

    4

   Instruments Defining the Rights of Security Holders. Murphy is party to several long-term debt instruments in addition to those in Exhibit 4.1 and 4.2, none of which authorizes securities exceeding 10% of the total consolidated assets of Murphy and its subsidiaries. Pursuant to Regulation S-K, item 601(b), paragraph 4(iii)(A), Murphy agrees to furnish a copy of each such instrument to the Securities and Exchange Commission upon request.   

    4.1

   Form of Second Supplemental Indenture between Murphy Oil Corporation and SunTrust Bank, as Trustee    Exhibit 4.1 of Murphy’s Form 10-K report for the year ended December 31, 2008

    4.2

   Form of Indenture and Form of Supplemental Indenture between Murphy Oil Corporation and SunTrust Bank, as Trustee    Exhibit 4.2 of Murphy’s Form 10-K report for the year ended December 31, 2009

*10.1

   1992 Stock Incentive Plan as amended May 14, 1997, December 1, 1999, May 14, 2003 and December 7, 2005   

  10.2

   2007 Long-Term Incentive Plan    Exhibit 10.1 of Murphy’s Form 8-K report filed April 24, 2007

  10.3

   Employee Stock Purchase Plan as amended May 9, 2007    Exhibit C of Murphy’s definitive proxy statement (Definitive 14A) dated March 30, 2007

  10.4

   2008 Stock Plan for Non-Employee Directors, as approved by shareholders on May 14, 2008    Form S-8 report filed February 5, 2009

*12.1

   Computation of Ratio of Earnings to Fixed Charges   

*13

   2010 Annual Report to Security Holders   

*21

   Subsidiaries of the Registrant   

*23

   Consent of Independent Registered Public Accounting Firm   

*31.1

   Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002   

 

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Exhibit

No.

        

Incorporated by Reference to

*31.2

   Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002   

  32

   Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002    See footnote1 below.

  99.1

   Form of employee stock option    Exhibit 99.1 of Murphy’s Form 10-K report for the year ended December 31, 2009

  99.2

   Form of performance-based employee restricted stock unit grant agreement    Exhibit 99.2 of Murphy’s Form 10-K report for the year ended December 31, 2008

*99.3

   Form of non-employee director stock option   

  99.4

   Form of non-employee director restricted stock award    Exhibit 99.4 of Murphy’s Form 10-K report for the year ended December 31, 2006

  99.5

   Form of non-employee director restricted stock unit award    Exhibit 99.5 of Murphy’s Form 10-K report for the year ended December 31, 2008

101.INS

   XBRL Instance Document   

101.SCH

   XBRL Taxonomy Extension Schema Document   

101.CAL

   XBRL Taxonomy Extension Calculation Linkbase Document   

101.DEF

   XBRL Taxonomy Extension Definition Linkbase Document   

101.LAB

   XBRL Taxonomy Extension Labels Linkbase Document   

101.PRE

   XBRL Taxonomy Extension Presentation Linkbase   

 

1

These certifications will not be deemed to be filed with the Commission or incorporated by reference into any filing by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates such certifications by reference.

Attached as Exhibit 101 to this report are documents formatted in XBRL (Extensible Business Reporting Language). Users of this data are advised pursuant to Rule 406T of Regulation S-T that the interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of section 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise not subject to liability under these sections. The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”

 

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

MURPHY OIL CORPORATION

 

By:  

DAVID M. WOOD

   Date:  

February 28, 2011

  David M. Wood, President     

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 28, 2011 by the following persons on behalf of the registrant and in the capacities indicated.

 

WILLIAM C. NOLAN JR.

   

R. MADISON MURPHY

William C. Nolan Jr., Chairman and Director     R. Madison Murphy, Director

DAVID M. WOOD

   

NEAL E. SCHMALE

David M. Wood, President and Chief     Neal E. Schmale, Director
Executive Officer and Director    
(Principal Executive Officer)    

FRANK W. BLUE

   

DAVID J. H. SMITH

Frank W. Blue, Director     David J. H. Smith, Director

CLAIBORNE P. DEMING

   

CAROLINE G. THEUS

Claiborne P. Deming, Director     Caroline G. Theus, Director

ROBERT A. HERMES

   

KEVIN G. FITZGERALD

Robert A. Hermes, Director     Kevin G. Fitzgerald, Senior Vice President
    and Chief Financial Officer
    (Principal Financial Officer)

JAMES V. KELLEY

   

JOHN W. ECKART

James V. Kelley, Director     John W. Eckart
    Vice President and Controller
    (Principal Accounting Officer)

 

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REPORT OF MANAGEMENT – CONSOLIDATED FINANCIAL STATEMENTS

The management of Murphy Oil Corporation is responsible for the preparation and integrity of the accompanying consolidated financial statements and other financial data. The statements were prepared in conformity with U.S. generally accepted accounting principles appropriate in the circumstances and include some amounts based on informed estimates and judgments, with consideration given to materiality.

An independent registered public accounting firm, KPMG LLP, has audited the Company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board and provides an objective, independent opinion about the fair presentation of the consolidated financial statements. The Audit Committee of the Board of Directors appoints the independent registered public accounting firm; ratification of the appointment is solicited annually from the shareholders.

The Board of Directors appoints an Audit Committee annually to implement and to support the Board’s oversight function of the Company’s financial reporting, accounting policies, internal controls and independent registered public accounting firm. This Committee is composed solely of directors who are not employees of the Company. The Committee meets routinely with representatives of management, the Company’s audit staff and the independent registered public accounting firm to review and discuss the adequacy and effectiveness of the Company’s internal controls, the quality and clarity of its financial reporting, the scope and results of independent and internal audits, and to fulfill other responsibilities included in the Committee’s Charter. The independent registered public accounting firm and the Company’s audit staff have unrestricted access to the Committee, without management presence, to discuss audit findings and other financial matters.

Our report of management covering internal control over financial reporting and the associated report of the independent registered public accounting firm can be found at page F-2.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of Murphy Oil Corporation:

We have audited the accompanying consolidated balance sheets of Murphy Oil Corporation and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2010. In connection with our audits of the consolidated financial statements, we also have audited financial statement Schedule II. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Murphy Oil Corporation and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Murphy Oil Corporation’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2011 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

 

/s/ KPMG LLP

 

Dallas, Texas

February 28, 2011

 

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REPORT OF MANAGEMENT – INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). The Company’s internal controls have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements in accordance with U.S. generally accepted accounting principles. All internal control systems have inherent limitations, and therefore, can provide only reasonable assurance with respect to the reliability of financial reporting and preparation of consolidated financial statements.

Management has conducted an evaluation of the effectiveness of our internal control over financial reporting based on the criteria set forth in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2010.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of Murphy Oil Corporation:

We have audited Murphy Oil Corporation’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Murphy Oil Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Report of Management – Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Murphy Oil Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Murphy Oil Corporation as of December 31, 2010 and 2009, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2010, and our report dated February 28, 2011 expressed an unqualified opinion on those consolidated financial statements.

 

/s/ KPMG LLP

 

Dallas, Texas

February 28, 2011

 

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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

 

Years Ended December 31 (Thousands of dollars except per share amounts)

   2010     2009     2008  

Revenues

      

Sales and other operating revenues

   $ 23,401,117        18,918,181        27,360,625   

Gain on sale of assets

     884        3,709        133,717   

Interest and other income (loss)

     (56,930     90,502        (62,011
                        

Total revenues

     23,345,071        19,012,392        27,432,331   
                        

Costs and Expenses

      

Crude oil and product purchases

     18,142,253        14,547,589        21,649,742   

Operating expenses

     1,967,209        1,621,854        1,657,427   

Exploration expenses, including undeveloped lease amortization

     292,264        265,172        344,406   

Selling and general expenses

     279,164        242,266        228,490   

Depreciation, depletion and amortization

     1,164,782        919,055        667,265   

Impairment of properties

     0        5,240        0   

Accretion of asset retirement obligations

     31,858        26,154        24,484   

Redetermination of Terra Nova working interest

     18,582        83,498        0   

Interest expense

     53,172        53,005        73,611   

Interest capitalized

     (18,444     (28,614     (31,459
                        

Total costs and expenses

     21,930,840        17,735,219        24,613,966   
                        

Income from continuing operations before income taxes

     1,414,231        1,277,173        2,818,365   

Income tax expense

     616,150        536,656        1,073,616   
                        

Income from continuing operations

     798,081        740,517        1,744,749   

Income (loss) from discontinued operations, net of income taxes

     0        97,104        (4,763
                        

Net Income

   $ 798,081        837,621        1,739,986   
                        

Income per Common Share – Basic

      

Income from continuing operations

   $ 4.16        3.88        9.20   

Income (loss) from discontinued operations

     0        0.51        (0.02
                        

Net Income – Basic

   $ 4.16        4.39        9.18   
                        

Income per Common Share – Diluted

      

Income from continuing operations

   $ 4.13        3.85        9.08   

Income (loss) from discontinued operations

     0        0.50        (0.02
                        

Net Income – Diluted

   $ 4.13        4.35        9.06   
                        

Average Common shares outstanding – basic

     191,830,357        190,767,077        189,608,846   

Average Common shares outstanding – diluted

     193,157,814        192,468,450        192,133,672   

See notes to consolidated financial statements, page F-8.

 

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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

December 31 (Thousands of dollars)

   2010     2009  

Assets

    

Current assets

    

Cash and cash equivalents

   $ 535,825        301,144   

Canadian government securities with maturities greater than 90 days at the date of acquisition

     616,558        779,025   

Accounts receivable, less allowance for doubtful accounts of $7,954 in 2010 and $7,761 in 2009

     1,467,311        1,463,297   

Inventories, at lower of cost or market

    

Crude oil and blend stocks

     147,256        128,936   

Finished products

     388,162        384,250   

Materials and supplies

     226,795        220,796   

Prepaid expenses

     88,241        83,218   

Deferred income taxes

     80,545        15,029   
                

Total current assets

     3,550,693        3,375,695   

Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $6,040,996 in 2010 and $4,714,826 in 2009

     10,367,847        9,065,088   

Goodwill

     42,850        40,652   

Deferred charges and other assets

     271,853        274,924   
                

Total assets

   $ 14,233,243        12,756,359   
                

Liabilities and Stockholders’ Equity

    

Current liabilities

    

Current maturities of long-term debt

   $ 41        38   

Accounts payable

     2,237,920        1,539,523   

Income taxes payable

     358,764        387,164   

Other taxes payable

     206,951        165,934   

Other accrued liabilities

     109,918        88,949   

Deferred income taxes

     17,316        0   
                

Total current liabilities

     2,930,910        2,181,608   

Long-term debt

     939,350        1,353,183   

Deferred income taxes

     1,212,213        1,018,767   

Asset retirement obligations

     555,248        476,938   

Deferred credits and other liabilities

     395,972        379,837   

Stockholders’ equity

    

Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued

     0        0   

Common Stock, par $1.00, authorized 450,000,000 shares at December 31, 2010 and 2009, issued 193,293,526 shares at December 31, 2010 and 191,797,600 shares at December 31, 2009

     193,294        191,798   

Capital in excess of par value

     767,762        680,509   

Retained earnings

     6,800,992        6,204,316   

Accumulated other comprehensive income

     449,428        287,187   

Treasury stock

     (11,926     (17,784
                

Total stockholders’ equity

     8,199,550        7,346,026   
                

Total liabilities and stockholders’ equity

   $ 14,233,243        12,756,359   
                

See notes to consolidated financial statements, page F-8.

 

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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

Years Ended December 31 (Thousands of dollars)

   2010     2009     2008  

Operating Activities

      

Net income

   $ 798,081        837,621        1,739,986   

Adjustments to reconcile net income to net cash provided by operating activities

      

(Income) loss from discontinued operations

     0        (97,104     4,763   

Depreciation, depletion and amortization

     1,164,782        919,055        667,265   

Impairment of long-lived assets

     0        5,240        0   

Amortization of deferred major repair costs

     39,110        26,103        27,294   

Expenditures for asset retirements

     (36,506     (48,694     (9,240

Dry hole costs

     90,125        125,244        129,459   

Amortization of undeveloped leases

     108,026        83,213        112,052   

Accretion of asset retirement obligations

     31,858        26,154        24,484   

Deferred and noncurrent income tax charges

     143,388        97,213        233,076   

Pretax gains from disposition of assets

     (884     (3,709     (133,717

Net decrease (increase) in noncash operating working capital

     639,566        (194,690     93,710   

Other operating activities – net

     151,012        90,001        35,304   
                        

Net cash provided by continuing operations

     3,128,558        1,865,647        2,924,436   

Net cash provided (required) by discontinued operations

     0        (1,014     115,476   
                        

Net cash provided by operating activities

     3,128,558        1,864,633        3,039,912   
                        

Investing Activities

      

Property additions and dry hole costs

     (2,316,372     (1,978,598     (2,179,011

Acquisition of ethanol plants 1

     (40,000     (10,000     0   

Proceeds from sale of property, plant and equipment

     2,189        1,616        361,961   

Expenditures for major repairs

     (98,939     (30,253     (57,604

Purchase of investment securities 2

     (2,388,720     (2,531,515     (1,043,473

Proceeds from maturity of investment securities 2

     2,551,187        2,172,830        623,133   

Other investing activities – net

     (38,157     (34,050     (21,256

Investing activities of discontinued operations

      

Sales proceeds

     0        78,908        0   

Other

     0        (845     (6,949
                        

Net cash required by investing activities

     (2,328,812     (2,331,907     (2,323,199
                        

Financing Activities

      

Additions to long-term debt

     0        243,500        0   

Reductions of long-term debt

     (332,038     0        (487,612

Reductions of nonrecourse debt of a subsidiary

     (82,000     (2,572     (5,235

Proceeds from exercise of stock options and employee stock purchase plans

     42,995        12,746        29,687   

Excess tax benefits related to exercise of stock options

     11,672        4,143        20,288   

Cash dividends paid

     (201,405     (190,788     (166,501

Withholding tax on stock-based incentive awards

     (5,170     0        0   
                        

Net cash provided (required) by financing activities

     (565,946     67,029        (609,373
                        

Effect of exchange rate changes on cash and cash equivalents

     881        35,279        (114,937
                        

Net increase (decrease) in cash and cash equivalents

     234,681        (364,966     (7,597

Cash and cash equivalents at January 1

     301,144        666,110        673,707   
                        

Cash and cash equivalents at December 31

   $ 535,825        301,144        666,110   
                        

 

1

Excludes nonrecourse seller financing of $82 million related to the Company’s acquisition of the Hankinson, North Dakota, ethanol plant in 2009.

2

Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.

See notes to consolidated financial statements, page F-8.

 

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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

 

Years Ended December 31 (Thousands of dollars)

   2010     2009     2008  

Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued

     0        0        0   
                        

Common Stock – par $1.00, authorized 450,000,000 shares at December 31, 2010, 2009 and 2008, issued 193,293,526 shares at December 31, 2010, 191,797,600 shares at December 31, 2009 and 191,248,941 shares at December 31, 2008

      

Balance at beginning of year

   $ 191,798        191,249        189,973   

Exercise of stock options

     1,496        549        1,276   
                        

Balance at end of year

     193,294        191,798        191,249   
                        

Capital in Excess of Par Value

      

Balance at beginning of year

     680,509        631,859        547,185   

Exercise of stock options, including income tax benefits

     54,887        17,244        45,839   

Restricted stock transactions and other

     (9,688     2,473        7,089   

Stock-based compensation

     40,842        27,976        30,811   

Sale of stock under employee stock purchase plans

     1,212        957        935   
                        

Balance at end of year

     767,762        680,509        631,859   
                        

Retained Earnings

      

Balance at beginning of year

     6,204,316        5,557,483        3,983,998   

Net income for the year

     798,081        837,621        1,739,986   

Cash dividends – $1.05 per share in 2010, $1.00 per share in 2009 and $0.875 per share in 2008

     (201,405     (190,788     (166,501
                        

Balance at end of year

     6,800,992        6,204,316        5,557,483   
                        

Accumulated Other Comprehensive Income (Loss)

      

Balance at beginning of year

     287,187        (87,697     351,765   

Foreign currency translation gains (losses), net of income taxes

     165,940        375,951        (383,021

Retirement and postretirement benefit plan adjustments, net of income taxes

     (3,699     (1,067     (56,441
                        

Balance at end of year

     449,428        287,187        (87,697
                        

Treasury Stock

      

Balance at beginning of year

     (17,784     (13,949     (6,747

Sale of stock under employee stock purchase plans

     1,295        1,604        515   

Awarded restricted stock, net of forfeitures

     4,305        0        0   

Cancellation of performance-based restricted stock and forfeitures

     258        (5,439     (7,717
                        

Balance at end of year – 457,518 shares of Common Stock in 2010, 682,222 shares in 2009 and 535,135 shares in 2008

     (11,926     (17,784     (13,949
                        

Total Stockholders’ Equity

   $ 8,199,550        7,346,026        6,278,945   
                        

See notes to consolidated financial statements, page F-8.

 

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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

Years Ended December 31 (Thousands of dollars)

   2010     2009     2008  

Net income

   $ 798,081        837,621        1,739,986   

Other comprehensive income (loss), net of tax

      

Net gain (loss) from foreign currency translation

     165,940        375,951        (383,021

Retirement and postretirement benefit plan adjustments

     (3,699     (1,067     (56,441
                        

Other comprehensive income (loss)

     162,241        374,884        (439,462
                        

Comprehensive Income

   $ 960,322        1,212,505        1,300,524   
                        

See notes to consolidated financial statements, page F-8.

 

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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note A – Significant Accounting Policies

NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries. The Company produces oil and/or natural gas in the United States, Canada, the United Kingdom, Malaysia and Republic of the Congo and conducts oil and natural gas exploration activities worldwide. The Company has an interest in a Canadian synthetic oil operation, owns two petroleum refineries and two ethanol production facilities in the United States and one refinery in the United Kingdom. Murphy markets petroleum products under various brand names and to unbranded wholesale customers in the United States and United Kingdom. In 2010, the Company announced that it intends to sell its three refineries and U.K. marketing assets in 2011.

PRINCIPLES OF CONSOLIDATION – The consolidated financial statements include the accounts of Murphy Oil Corporation and all majority-owned subsidiaries. For consolidated subsidiaries that are less than wholly owned, the noncontrolling interest is reflected in the balance sheet as a component of Stockholders’ Equity. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. Investments in affiliates in which the Company owns from 20% to 50% are accounted for by the equity method. Other investments are generally carried at cost. All significant intercompany accounts and transactions have been eliminated.

REVENUE RECOGNITION – Revenues from sales of crude oil, natural gas and refined petroleum products are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer. Refined products sold at retail are recorded when the customer takes delivery at the pump. Merchandise revenues are recorded at the point of sale. Revenues from the production of oil and natural gas properties in which Murphy shares an undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period. Gas imbalances occur when the Company’s actual sales differ from its entitlement under existing working interests. The Company records a liability for gas imbalances when it has sold more than its working interest of gas production and the estimated remaining reserves make it doubtful that partners can recoup their share of production from the field. At December 31, 2010 and 2009, the liabilities for natural gas balancing were immaterial.

The Company enters into buy/sell and similar arrangements when crude oil and other petroleum products are held at one location but are needed at a different location. The Company often pays or receives funds related to the buy/sell arrangement based on location or quality differences. The Company accounts for such transactions on a net basis in its consolidated statement of income.

TAXES COLLECTED FROM CUSTOMERS AND REMITTED TO GOVERNMENT AUTHORITIES – Excise and other taxes collected on sales of refined products and remitted to governmental agencies are excluded from revenues and costs and expenses in the Consolidated Statement of Income.

CASH EQUIVALENTS – Short-term investments, which include government securities and other instruments with government securities as collateral, that have a maturity of three months or less from the date of purchase are classified as cash equivalents.

MARKETABLE SECURITIES – The Company classifies investments in marketable securities as available-for-sale or held-to-maturity. The Company does not have any investments classified as trading. Available-for-sale securities are carried at fair value with the unrealized gain or loss, net of tax, reported in other comprehensive income. Held-to-maturity securities are recorded at amortized cost. Premiums and discounts are amortized or accreted into earnings over the life of the related available-for-sale or held-to-maturity security. Dividend and interest income is recognized when earned. Unrealized losses considered to be “other than

 

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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

temporary” are recognized currently in earnings. The cost of securities sold is based on the specific identification method. The fair value of investment securities is determined by available market prices. At December 31, 2010, the Company owned Canadian government securities with maturities greater than 90 days at date of acquisition that had a carrying value of $616,558,000.

ACCOUNTS RECEIVABLE – The Company’s accounts receivable primarily consists of amounts owed to the Company by customers for sales of crude oil, natural gas and refined products under varying credit arrangements. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses on these receivables. The Company reviews this allowance for adequacy at least quarterly and bases its assessment on a combination of current information about its customers and historical write-off experience. Any trade accounts receivable balances written off are charged against the allowance for doubtful accounts. The Company has not experienced any significant credit-related losses in the past three years.

PROPERTY, PLANT AND EQUIPMENT – The Company uses the successful efforts method to account for exploration and development expenditures. Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Costs of undeveloped leases are generally expensed over the life of the leases. Exploratory well costs are capitalized pending determination about whether proved reserves have been found. In certain cases, a determination of whether a drilled exploratory well has found proved reserves can not be made immediately. This is generally due to the need for a major capital expenditure to produce and/or evacuate the hydrocarbon(s) found. The determination of whether to make such a capital expenditure is usually dependent on whether further exploratory wells find a sufficient quantity of additional reserves. The Company continues to capitalize exploratory well costs in Property, Plant and Equipment 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. The Company reevaluates its capitalized drilling costs at least annually to ascertain whether drilling costs continue to qualify for ongoing capitalization. Other exploratory costs, including geological and geophysical costs, are charged to expense as incurred. Development costs, including unsuccessful development wells, are capitalized. Interest is capitalized on development projects that are expected to take one year or more to complete.

Oil and gas properties are evaluated by field for potential impairment. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets as applicable. An impairment is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to fair value.

The Company records a liability for asset retirement obligations (ARO) equal to the fair value of the estimated cost to retire an asset. The ARO liability is initially recorded in the period in which the obligation meets the definition of a liability, which is generally when a well is drilled or the asset is placed in service. The ARO liability is estimated by the Company’s engineers using existing regulatory requirements and anticipated future inflation rates. When the liability is initially recorded, the Company increases the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is increased over time to reflect the change in its present value, and the capitalized cost is depreciated over the useful life of the related long-lived asset. The Company reevaluates the adequacy of its recorded ARO liability at least annually. Actual costs of asset retirements such as dismantling oil and gas production facilities and site restoration are charged against the related liability. Any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability is recognized as a gain or loss in the Company’s earnings.

Depreciation and depletion of producing oil and gas properties is recorded based on units of production. Unit rates are computed for unamortized exploration drilling and development costs using proved developed reserves;

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

unit rates for unamortized leasehold costs and asset retirement costs are amortized over proved reserves. Proved reserves are estimated by the Company’s engineers and are subject to future revisions based on availability of additional information. Refineries, certain marketing facilities and certain common natural gas processing facilities are depreciated primarily using the composite straight-line method with depreciable lives ranging from 14 to 25 years. Gasoline stations and other properties are depreciated over 3 to 20 years by individual unit on the straight-line method. Gains and losses on asset disposals or retirements are included in income as a separate component of revenues.

Turnarounds for major processing units are scheduled at four to five year intervals at the Company’s three refineries. Turnarounds for coking units at Syncrude Canada Ltd. are scheduled at intervals of two to three years. Turnaround work associated with various other less significant units at the Company’s refineries and Syncrude will vary depending on operating requirements and events. Murphy defers turnaround costs incurred and amortizes such costs through Operating Expenses over the period until the next scheduled turnaround. All other maintenance and repairs are expensed as incurred. Renewals and betterments are capitalized. Major turnarounds occurred in 2010 at both the Meraux, Louisiana, and Milford Haven, Wales, refineries.

INVENTORIES – Unsold crude oil production is carried in inventory at the lower of cost, generally applied on a first-in, first-out (FIFO) basis, or market, and include costs incurred to bring the inventory to its existing condition. Refinery inventories of crude oil and other feedstocks and finished product inventories are valued at the lower of cost, generally applied on a last-in, first-out (LIFO) basis, or market. Inventory held for resale at retail marketing stations is generally carried at average cost and is included in Finished Products Inventory. Materials and supplies are valued at the lower of average cost or estimated value and generally consist of tubulars and other drilling equipment as well as spare parts for refinery operations. Cash collected upon the sale of inventory to customers is classified as an operating activity in the Consolidated Statement of Cash Flows.

GOODWILL – Goodwill is recorded in an acquisition when the purchase price exceeds the fair value of net assets acquired. All recorded goodwill arose from the purchase of an oil and natural gas company by Murphy’s wholly owned Canadian subsidiary in 2000. Goodwill is not amortized, but is assessed at least annually for recoverability of the carrying value. The Company assesses goodwill recoverability at each year-end by comparing the fair value of net assets for conventional oil and natural gas properties in Canada with the carrying value of these net assets including goodwill. The fair value of the conventional oil and natural gas reporting unit is determined using the expected present value of future cash flows. The change in the carrying value of goodwill during 2010 was primarily caused by a change in the foreign currency translation rate between years. Based on its assessment of the fair value of its Canadian conventional oil and natural gas operations, the Company believes the recorded value of goodwill is not impaired at December 31, 2010. Should a future assessment indicate that goodwill is not fully recoverable, an impairment charge to write down the carrying value of goodwill would be required.

ENVIRONMENTAL LIABILITIES – A liability for environmental matters is established when it is probable that an environmental obligation exists 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. Related expenditures are charged against the liability. Environmental remediation liabilities have not been discounted for the time value of future expected payments. Environmental expenditures that have future economic benefit are capitalized.

INCOME TAXES – The Company accounts for income taxes using the asset and liability method. Under this method, income taxes are provided for amounts currently payable and for amounts deferred as tax assets and liabilities based on differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities. Deferred income taxes are measured using the enacted tax rates that are assumed will be in

 

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effect when the differences reverse. Petroleum revenue taxes are provided using the estimated effective tax rate over the life of applicable U.K. properties. The accounting rules for income tax uncertainties permit recognition of income tax benefits only when they are more likely than not to be realized. The Company includes potential penalties and interest for uncertain income tax positions in income tax expense.

FOREIGN CURRENCY – Local currency is the functional currency used for recording operations in Canada and Spain and for refining and marketing activities in the United Kingdom. The U.S. dollar is the functional currency used to record all other operations. Exchange gains or losses from transactions in a currency other than the functional currency are included in earnings. Gains or losses from translating foreign functional currency into U.S. dollars are included in Accumulated Other Comprehensive Income (Loss) in Stockholders’ Equity.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES – The fair value of a derivative instrument is recognized as an asset or liability in the Company’s Consolidated Balance Sheet. Upon entering into a derivative contract, the Company may designate the derivative as either a fair value hedge or a cash flow hedge, or decide that the contract is not a hedge, and thenceforth, recognize changes in the fair value of the contract in earnings. The Company documents the relationship between the derivative instrument designated as a hedge and the hedged items as well as its objective for risk management and strategy for use of the hedging instrument to manage the risk. Derivative instruments designated as fair value or cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions. The Company assesses at inception and on an ongoing basis whether a derivative instrument used as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting. Changes in the fair value of a qualifying fair value hedge are recorded in earnings along with the gain or loss on the hedged item. Changes in the fair value of a qualifying cash flow hedge are recorded in other comprehensive income until the hedged item is recognized in earnings. When the income effect of the underlying cash flow hedged item is recognized in the Statement of Income, the fair value of the associated cash flow hedge is reclassified from other comprehensive income into earnings. Ineffective portions of a cash flow hedge derivative’s change in fair value are recognized currently in earnings. If a derivative instrument no longer qualifies as a cash flow hedge and the underlying forecasted transaction is no longer probable of occurring, hedge accounting is discontinued and the gain or loss recorded in other comprehensive income is recognized immediately in earnings.

STOCK-BASED COMPENSATION – The fair value of awarded stock options, restricted stock and restricted stock units is determined based on a combination of management assumptions and the market value of the Company’s common stock. The Company uses the Black-Scholes option pricing model for computing the fair value of stock options. The primary assumptions made by management include the expected life of the stock option award and the expected volatility of Murphy’s common stock prices. The Company uses both historical data and current information to support its assumptions. Stock option expense is recognized on a straight-line basis over the respective vesting period of two or three years. The Company uses a Monte Carlo valuation model to determine the fair value of performance-based restricted stock and restricted stock units and expense is recognized over the three-year vesting period. The fair value of time-lapse restricted stock is determined based on the price of Company stock on the date of grant and expense is recognized over the vesting period. The Company estimates the number of stock options and performance-based restricted stock and restricted stock units that will not vest and adjusts its compensation expense accordingly. Differences between estimated and actual vested amounts are accounted for as an adjustment to expense when known.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

NET INCOME PER COMMON SHARE – Basic income per Common share is computed by dividing net income for each reporting period by the weighted average number of Common shares outstanding during the period. Diluted income per Common share is computed by dividing net income for each reporting period by the weighted average number of Common shares outstanding during the period plus the effects of all potentially dilutive Common shares.

USE OF ESTIMATES – In preparing the financial statements of the Company in conformity with U.S. generally accepted accounting principles, management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.

Note B – New Accounting Principles and Recent Accounting Pronouncements

New Accounting Principles Adopted

The Company adopted new guidance issued by the Financial Accounting Standards Board (FASB) regarding accounting for transfers of financial assets effective January 1, 2010. This guidance makes the concept of a qualifying special-purpose entity as defined previously no longer relevant for accounting purposes. Therefore, formerly qualifying special-purpose entities must be reevaluated for consolidation by reporting entities in accordance with the applicable consolidation guidance. This adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted, effective January 1, 2010, new guidance issued by the FASB that requires a company to perform an analysis to determine whether its variable interests give it a controlling financial interest in a variable interest entity. The primary beneficiary of a variable interest entity has both the power to direct the activities of the entity that most significantly impact the entity’s economic performance and the obligation to absorb potentially significant losses of the entity or the right to receive potentially significant benefits from the entity. A company is required to make ongoing reassessments of whether it is the primary beneficiary of a variable interest entity. This guidance also amends previous guidance for determining whether an entity is considered a variable interest entity. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

In July 2010, the FASB issued new accounting guidance that expands the disclosure requirements about financing receivables and the related allowance for credit losses. This guidance became effective for the Company at December 31, 2010. Because the Company has no significant financing receivables that extend beyond one year, the impact of this guidance did not have a significant effect on its consolidated financial statement disclosures.

The Company adopted new accounting guidance for noncontrolling interests in consolidated financial statements effective January 1, 2009. This guidance was applied prospectively, except for presentation and disclosure requirements which are applied retrospectively. This guidance required noncontrolling interests to be reclassified as equity, and consolidated net income and comprehensive income shall include the respective results attributable to noncontrolling interests. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted new accounting guidance covering business combinations effective January 1, 2009. The new guidance established principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquired business. It also established how to recognize and measure goodwill

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

acquired in the business combination or a gain from a bargain purchase, if applicable. This guidance impacts the recognition and measurement of assets and liabilities in business combinations that occur beginning in 2009. Assets and liabilities that arose from business combinations that occurred prior to 2009 are not affected by this guidance. The adoption of this guidance did not have a significant effect on the Company’s financial statements for the year ended December 31, 2009. The Company is unable to predict how the application of this guidance will affect its financial statements in future periods.

The Company adopted new accounting guidance which addressed disclosures about derivative instruments and hedging activities in January 2009. This guidance expanded required disclosures regarding derivative instruments to include qualitative information about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts and gains and losses on derivative instruments, and disclosures about credit-risk related contingent features in derivative agreements. See Note L for further disclosures.

In 2009, the Company adopted new accounting guidance for determining whether instruments granted in share-based payment transactions are participating securities. This guidance specified that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings per share (EPS) calculation under the two-class method, and also required that all prior-period EPS calculations be adjusted retrospectively. The adoption of this guidance did not have a significant impact on the Company’s prior-period EPS calculations.

The Company adopted new accounting guidance addressing certain equity method investment accounting considerations in January 2009. The guidance, which has been applied prospectively, addressed how to initially measure contingent consideration for an equity method investment, how to recognize other-than-temporary impairments of an equity method investment, and how an equity method investor is to account for a share issuance by an investee. The adoption of this guidance did not have a significant impact on the Company’s consolidated financial statements.

The Company adopted new accounting guidance addressing subsequent events effective June 30, 2009. The guidance clarified the accounting for and disclosure of subsequent events that occur after the balance sheet date through the date of issuance of the applicable financial statements. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The FASB’s Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles guidance became effective for interim and annual periods ended after September 15, 2009, and it recognized the FASB Accounting Standards Codification as the single source of authoritative nongovernment U.S. generally accepted accounting principles. The codification superseded all existing accounting standards documents issued by the FASB, and established that all other accounting literature not included in the codification is considered nonauthoritative. Although the codification did not change U.S. generally accepted accounting principles, it did reorganize the principles into accounting topics using a consistent structure. The codification also includes relevant U.S. Securities and Exchange Commission guidance following the same topical structure. Subsequent to adoption of this statement, all references to U.S. generally accepted accounting principles use the new topical guidelines established with the codification. Otherwise, this new standard did not have a material impact on the Company’s consolidated financial statements.

The FASB has provided additional guidance regarding disclosures about postretirement benefit plan assets, including how asset investment allocation decisions are made, the fair value of each major category of plan assets, and how fair value is determined for each major asset category. This guidance was effective for the Company as of December 31, 2009. Upon adoption, no comparative disclosures were required for earlier years presented. See Note K for these disclosures.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

In December 2008, the U.S. Securities and Exchange Commission (SEC) adopted revisions to oil and natural gas reserves reporting requirements which became effective for the Company at year-end 2009. The primary changes to reserves reporting included:

 

   

A revised definition of proved reserves, including the use of unweighted average oil and natural gas prices in effect at the beginning of each month during the year to compute such reserves,

 

   

Expanding the definition of oil and gas producing activities to include non-traditional and unconventional resources, which includes the Company’s Canadian synthetic oil operations at Syncrude,

 

   

Allowing companies to voluntarily disclose probable and possible reserves in SEC filings,

 

   

Amending required proved reserve disclosures to include separate amounts for synthetic oil and gas,

 

   

Expanded disclosures of proved undeveloped reserves, including discussion of such proved undeveloped reserves five years old or more, and

 

   

Disclosure of the qualifications of the chief technical person who oversees the Company’s overall reserve process.

The Company utilized this new guidance at December 31, 2010 and 2009 to determine its proved reserves and to develop associated disclosures. The Company chose not to provide voluntary disclosures of probable and possible reserves in this Form 10-K. In January 2010, the FASB issued guidance that aligned its oil and gas reporting requirements and effective date with the SEC’s guidance described above.

Recent Accounting and Reporting Rules

The United States Congress passed the Dodd-Frank Act in 2010. Among other requirements, the law requires companies in the oil and gas industry to disclose payments made to the U.S. Federal and all foreign governments. The SEC was directed to develop the reporting requirements in accordance with the law. The SEC has issued preliminary guidance and is seeking feedback thereon from all interested parties. The preliminary rules indicated that payment disclosures would be required at a project level within the annual Form 10-K report beginning with the year ending December 31, 2012. The Company cannot predict the final disclosure requirements that will be required by the SEC.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Note C – Discontinued Operations

On March 12, 2009, the Company sold its operations in Ecuador for net cash proceeds of $78,900,000. The acquirer also assumed certain tax and other liabilities associated with the Ecuador properties sold. The Ecuador properties sold included 20% interests in producing Block 16 and the nearby Tivacuno area. The Company recorded a gain of $103,596,000, net of income taxes of $13,961,000, from the sale of the Ecuador properties in 2009. Ecuador operating results prior to the sale, and the resulting gain on disposal, have been reported as discontinued operations. The major assets (liabilities) associated with the Ecuador properties at the time of the sale are presented in the following table.

 

(Thousands of dollars)

      

Current assets

   $ 4,214   

Property, plant and equipment, net of accumulated depreciation, depletion and amortization

     65,178   

Other noncurrent assets

     683   
        

Assets sold

   $ 70,075   
        

Current liabilities

   $ 105,185   

Other noncurrent liabilities

     35   
        

Liabilities associated with assets sold

   $ 105,220   
        

The following table reflects the results of operations, including the gain on sale, from the Ecuador properties sold in 2009.

 

(Thousands of dollars)

   2009      2008  

Revenues

   $ 125,654         80,209   

Income before income tax expense, including a gain on disposal of $117,557 in 2009

     109,865         188   

Income tax expense

     12,761         4,951   

Note D – Acquisitions

In August 2010, a wholly-owned subsidiary of the Company purchased an unfinished ethanol production facility in Hereford, Texas, for $40,000,000. The Company expects the construction of the facility to be completed and in operation by the end of the first quarter of 2011. The Company has allocated the purchase price for the Hereford facility as of acquisition date based on the estimated fair value of the assets acquired as presented in the following table.

 

(Thousands of dollars)

      

Land and land improvements

   $ 2,379   

Buildings and improvements

     639   

Machinery and transportation equipment

     36,982   
        

Total purchase price

   $ 40,000   
        

A wholly-owned subsidiary of the Company purchased an ethanol production facility in Hankinson, North Dakota, on October 1, 2009. The facility has a rated capacity to produce 110 million gallons of ethanol per annum. The $92,000,000 purchase price was financed with an $82,000,000 nonrecourse loan held by former owners. The loan bore interest at 5.0% per year and was repayable in 2014. This loan was repaid in full in

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

September 2010. Revenue and expenses associated with the facility have been included in the Company’s consolidated statement of income beginning on the date of acquisition. The Company has allocated the purchase price for the Hankinson facility as of acquisition date based on the estimated fair value of the assets acquired as presented in the following table.

 

(Thousands of dollars)

      

Inventory

   $ 2,469   

Land and land improvements

     11,833   

Buildings and improvements

     9,819   

Machinery and transportation equipment

     67,879   
        

Total purchase price

   $ 92,000   
        

Note E – Property, Plant and Equipment

 

     December 31, 2010     December 31, 2009  

(Thousands of dollars)

   Cost      Net     Cost      Net  

Exploration and production1

   $ 12,506,579         7,898,417 2      10,258,126         6,834,178 2 

Refining

     2,266,883         1,301,128        1,900,551         1,048,067   

Marketing

     1,527,340         1,108,282        1,518,349         1,120,494   

Corporate and other

     108,041         60,020        102,888         62,349   
                                  
   $ 16,408,843         10,367,847        13,779,914         9,065,088   
                                  

 

          

1         Includes mineral rights as follows:

   $ 779,036         432,051        576,543         326,382   

2        Includes $17,067 in 2010 and $11,773 in 2009 related to administrative assets and support equipment.

            

In January 2008, the Company sold its interest in Berkana Energy Corporation and recorded a pretax gain of $41,950,000 ($40,161,000 after-tax). In May 2008, the Company sold its interest in the Lloydminster area properties in Western Canada for a pretax gain of $90,451,000 ($67,236,000 after-tax).

Under FASB guidance exploratory well costs should continue to be capitalized 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.

At December 31, 2010, 2009 and 2008, the Company had total capitalized drilling costs pending the determination of proved reserves of $497,765,000, $369,862,000, and $310,118,000, respectively. The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 2010.

 

(Thousands of dollars)

   2010     2009     2008  

Beginning balance at January 1

   $ 369,862        310,118        272,155   

Additions to capitalized exploratory well costs pending the determination of proved reserves

     137,403        119,995        44,832   

Reclassifications to proved properties based on the determination of proved reserves

     0        (60,251     (6,869

Capitalized exploratory well costs charged to expense or sold

     (9,500     0        0   
                        

Ending balance at December 31

   $ 497,765        369,862        310,118   
                        

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized since the completion of drilling.

 

     2010      2009      2008  

(Thousands of dollars)

   Amount      No. of
Wells
     No. of
Projects
     Amount      No. of
Wells
     No. of
Projects
     Amount      No. of
Wells
     No. of
Projects
 

Aging of capitalized well costs:

                          

Zero to one year

   $ 135,494         15         4       $ 117,618         10         6       $ 48,424         4         4   

One to two years

     115,418         10         4         49,628         4         4         8,870         7         0   

Two to three years

     42,571         3         3         8,870         5         0         101,151         18         4   

Three years or more

     204,282         31         4         193,746         27         4         151,673         14         4   
                                                                                
   $ 497,765         59         15       $ 369,862         46         14       $ 310,118         43         12   
                                                                                

Of the $362,271,000 of exploratory well costs capitalized more than one year at December 31, 2010, $235,418,000 is in Malaysia, $104,694,000 is in the U.S., $15,078,000 is in Republic of the Congo and $7,081,000 is in Canada. In Malaysia either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. In the U.S. further drilling is anticipated and development plans are being formulated. In Republic of the Congo further appraised drilling is planned. In Canada a continuing drilling and development program is underway.

In July 2010, the Company announced that its Board of Directors had approved plans to exit the U.S. refining and U.K. refining and marketing businesses. These operations, which have been placed for sale, are included within the U.S. manufacturing and U.K. refining and marketing segments presented in Note U. The Company currently anticipates the sale of these operations to be completed in 2011. The Company expects that the results of these operations will be presented as discontinued operations in future periods when the criteria for held for sale under U.S. generally accepted accounting principles have been met.

Note F – Financing Arrangements

At December 31, 2010, the Company had a $1,905,000,000 committed credit facility with a major banking consortium that matures in June 2012. Between June 2011 and June 2012, the capacity of the committed facility is reduced to $1,827,500,000. At December 31, 2010, the Company had borrowed $340,000,000 under this committed facility. Borrowings under this facility bear interest at prime or varying cost of fund options. Facility fees are due at varying rates on the commitment. At December 31, 2010, the Company had no borrowings under uncommitted credit lines that amount to approximately $430,000,000. If necessary, the Company could borrow funds under all or certain of these uncommitted lines with various financial institutions in future periods. The Company has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through September 2012.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Note G – Long-term Debt

 

     December 31  

(Thousands of dollars)

   2010     2009  

Notes payable

    

6.375% notes, due 2012, net of unamortized discount of $154 at December 31, 2010

   $     349,846        349,731   

7.05% notes, due 2029, net of unamortized discount of $1,709 at December 31, 2010

     248,291        248,199   

Notes payable to banks, 0.7375% at December 31, 2010

     340,000        672,000   

Other, 6%, due through 2028

     1,254        1,291