UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
For the quarterly period ended March 31, 2011
OR
For the transition period from to
Commission File Number 1-8590
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification Number)
200 Peach Street
P.O. Box 7000, El Dorado, Arkansas
(870) 862-6411
(Registrant’s telephone number, including area code)
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. x Yes ¨ 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). x Yes ¨ No
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.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes x No
Number of shares of Common Stock, $1.00 par value, outstanding at March 31, 2011 was 193,426,362.
TABLE OF CONTENTS
Part I – Financial Information
Item 1. Financial Statements
Consolidated Statements of Income
Consolidated Balance Sheets
Consolidated Statements of Comprehensive Income
Consolidated Statements of Cash Flows
Consolidated Statements of Stockholders’ Equity
Notes to Consolidated Financial Statements
Item 2. Management’s Discussion and Analysis of Results of Operations and Financial Condition
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
Part II – Other Information
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 6. Exhibits
Signature
1
PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME (unaudited)
(Thousands of dollars, except per share amounts)
REVENUES
Sales and other operating revenues
Gain on sale of assets
Interest and other income (expense)
Total revenues
COSTS AND EXPENSES
Crude oil and product purchases
Operating expenses
Exploration expenses, including undeveloped lease amortization
Selling and general expenses
Depreciation, depletion and amortization
Accretion of asset retirement obligations
Redetermination of Terra Nova working interest
Interest expense
Interest capitalized
Total costs and expenses
Income before income taxes
Income tax expense
NET INCOME
NET INCOME PER COMMON SHARE
Basic
Diluted
Average Common shares outstanding
See Notes to Consolidated Financial Statements, page 7.
The Exhibit Index is on page 28.
2
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
ASSETS
Current assets
Cash and cash equivalents
Canadian government securities with maturities greater than 90 days at the date of acquisition
Accounts receivable, less allowance for doubtful accounts of $7,953 in 2011 and $7,954 in 2010
Inventories, at lower of cost or market
Crude oil and blend stocks
Finished products
Materials and supplies
Prepaid expenses
Deferred income taxes
Total current assets
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $6,418,505 in 2011 and $6,040,996 in 2010
Goodwill
Deferred charges and other assets
Total assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt
Accounts payable and accrued liabilities
Income taxes payable
Total current liabilities
Long-term debt
Asset retirement obligations
Deferred credits and other liabilities
Stockholders’ equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued
Common Stock, par $1.00, authorized 450,000,000 shares, issued 193,636,851 shares in 2011 and 193,293,526 shares in 2010
Capital in excess of par value
Retained earnings
Accumulated other comprehensive income
Treasury stock, 210,489 shares of Common Stock in 2011 and 457,518 shares of Common Stock in 2010, at cost
Total stockholders’ equity
Total liabilities and stockholders’ equity
3
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)
Net income
Other comprehensive income, net of income taxes
Net gain from foreign currency translation
Retirement and postretirement benefit plan adjustments
COMPREHENSIVE INCOME
4
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
OPERATING ACTIVITIES
Adjustments to reconcile net income to net cash provided by operating activities
Amortization of deferred major repair costs
Expenditures for asset retirements
Dry hole costs
Amortization of undeveloped leases
Deferred and noncurrent income tax charges (benefits)
Pretax gain from disposition of assets
Net decrease (increase) in noncash operating working capital
Other operating activities, net
Net cash provided by operating activities
INVESTING ACTIVITIES
Property additions and dry hole costs
Purchases of investment securities*
Proceeds from maturity of investment securities*
Expenditures for major repairs
Proceeds from sales of assets
Other – net
Net cash required by investing activities
FINANCING ACTIVITIES
Borrowing (repayment) of notes payable
Proceeds from exercise of stock options and employee stock purchase plans
Withholding tax on stock-based incentive awards
Excess tax benefits related to exercise of stock options
Cash dividends paid
Net cash required by financing activities
Effect of exchange rate changes on cash and cash equivalents
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at January 1
Cash and cash equivalents at March 31
5
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued
Common Stock – par $1.00, authorized 450,000,000 shares, issued 193,636,851 shares at March 31, 2011 and 191,988,394 shares at March 31, 2010
Balance at beginning of period
Exercise of stock options
Balance at end of period
Capital in Excess of Par Value
Exercise of stock options, including income tax benefits
Stock-based compensation
Sale of stock under employee stock purchase plans
Restricted stock transactions and other
Retained Earnings
Net income for the period
Cash dividends
Accumulated Other Comprehensive Income
Foreign currency translation gains, net of income taxes
Retirement and postretirement benefit plan adjustments, net of income taxes
Treasury Stock
Awarded restricted stock, net of forfeitures
Total Stockholders’ Equity
See notes to consolidated financial statements, page 7
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 2 through 6 of this Form 10-Q report.
Note A – Interim Financial Statements
The consolidated financial statements of the Company presented herein have not been audited by independent auditors, except for the Consolidated Balance Sheet at December 31, 2010. In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at March 31, 2011, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended March 31, 2011 and 2010, in conformity with accounting principles generally accepted in the United States. In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the United States, 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.
Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2010 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month period ended March 31, 2011 are not necessarily indicative of future results.
Note B – Property, Plant and Equipment
Under U.S. generally accepted accounting principles for companies that use the successful efforts method of accounting, 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 March 31, 2011, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $500.7 million. The following table reflects the net changes in capitalized exploratory well costs during the three-month periods ended March 31, 2011 and 2010.
Beginning balance at January 1
Additions pending the determination of proved reserves
Reclassifications to proved properties based on the determination of proved reserves
Balance at March 31
The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs have been capitalized. The projects are aged based on the last well drilled in the project.
Aging of capitalized well costs:
Zero to one year
One to two years
Two to three years
Three years or more
Of the $368.1 million of exploratory well costs capitalized more than one year at March 31, 2011, $237.1 million is in Malaysia, $104.3 million is in the U.S., $15.2 million is in Republic of the Congo, and $11.5 million 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. drilling and development operations are planned. In Republic of the Congo further appraisal drilling is planned. In Canada a continuing drilling and development program is underway.
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note B – Property, Plant and Equipment (Contd.)
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 encompassed within the U.S. manufacturing and U.K. refining and marketing segments presented in Note P. 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 C – Inventories
Inventories are carried at the lower of cost or market. The cost of crude oil and finished products is predominantly determined on the last-in, first-out (LIFO) method. At March 31, 2011 and December 31, 2010, the carrying values of inventories under the LIFO method were $950.3 million and $735.1 million, respectively, less than such inventories would have been valued using the first-in, first-out (FIFO) method.
Note D – Cash Flow Disclosures
Additional disclosures regarding cash flow activities are provided below.
Net (increase) decrease in operating working capital other than cash and cash equivalents:
(Increase) decrease in accounts receivable
(Increase) decrease in inventories
(Increase) decrease in prepaid expenses
(Increase) decrease in deferred income tax assets
Increase (decrease) in accounts payable and accrued liabilities
Increase (decrease) in current income tax liabilities
Total
Supplementary disclosures:
Cash income taxes paid
Interest paid more (less) than amounts capitalized
Note E – Employee and Retiree Benefit Plans
The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors’ plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.
The table that follows provides the components of net periodic benefit expense for the three-month periods ended March 31, 2011 and 2010.
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service cost
Amortization of transitional asset
Recognized actuarial loss
Net periodic benefit expense
8
Note E – Employee and Retiree Benefit Plans (Contd.)
During the three-month period ended March 31, 2011, the Company made contributions of $18.7 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2011 for the Company’s defined benefit pension and postretirement plans is anticipated to be $26.6 million.
In March 2010, the United States Congress enacted a health care reform law. Along with other provisions, the law (a) eliminates the tax free status of federal subsidies to companies with qualified retiree prescription drug plans that are actuarially equivalent to Medicare Part D plans beginning in 2013; (b) imposes a 40% excise tax on high-cost health plans as defined in the law beginning in 2018; (c) eliminates lifetime or annual coverage limits and required coverage for preventative health services beginning in September 2010; and (d) imposed a fee of $2 (subsequently adjusted for inflation) for each person covered by a health insurance policy beginning in September 2010. The Company provides a health care benefit plan to eligible U.S. employees and most U.S. retired employees. The new law did not significantly affect the Company’s consolidated financial statements as of March 31, 2011 and 2010 and for the three-month periods then ended. The Company continues to evaluate the various components of the law as further guidance is issued and cannot predict with certainty all the ways it may impact the Company. However, based on the evaluation performed to date, the Company currently believes that the health care reform law will not have a material effect on its financial condition, net income or cash flow in future periods.
Note F – Incentive Plans
The costs resulting from all share-based payment transactions are recognized as an expense in the financial statements using a fair value-based measurement method over the periods that the awards vest.
The 2007 Annual Incentive Plan (2007 Annual Plan) authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and other key employees. Cash awards under the 2007 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee. The 2007 Long-Term Incentive Plan (2007 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units, performance units, performance shares, dividend equivalents and other stock-based incentives. The 2007 Long-Term Plan expires in 2017. A total of 6,700,000 shares are issuable during the life of the 2007 Long-Term Plan, with annual grants limited to 1% of Common shares outstanding. The Company has an Employee Stock Purchase Plan that permits the issuance of up to 980,000 shares through September 30, 2017. The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock and stock options or a combination thereof to the Company’s Directors.
In February 2011, the Committee granted stock options for 1,397,312 shares at an exercise price of $67.635 per share. The Black-Scholes valuation for these awards was $20.34 per option. The Committee also granted 521,423 performance-based restricted stock units in February 2011 under the 2007 Long-Term Plan. The fair value of the performance-based restricted stock units, using a Monte Carlo valuation model, ranged from $38.94 to $64.89 per unit. Also in February the Committee granted 29,115 shares of time-based restricted stock to the Company’s Directors under the 2008 Non-employee Director Plan. These shares vest on the third anniversary of the date of grant. The fair value of these awards was estimated based on the fair market value of the Company’s stock on the date of grant, which was $67.64 per share.
Cash received from options exercised under all share-based payment arrangements for the three-month periods ended March 31, 2011 and 2010 was $6.8 million and $5.6 million, respectively. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $6.0 million and $2.5 million for the three-month periods ended March 31, 2011 and 2010, respectively.
Amounts recognized in the financial statements with respect to share-based plans are as follows.
Compensation charged against income before tax benefit
Related income tax benefit recognized in income
9
Note G – Earnings per Share
Net income was used as the numerator in computing both basic and diluted income per Common share for the three-months ended March 31, 2011 and 2010. The following table reconciles the weighted-average shares outstanding used for these computations.
(Weighted-average shares)
Basic method
Dilutive stock options
Diluted method
Certain options to purchase shares of common stock were outstanding during the 2011 and 2010 periods but were not included in the computation of diluted EPS because the incremental shares from assumed conversion were antidilutive. These included 697,994 shares at a weighted average share price of $67.64 in the 2011 period and 3,271,753 shares at a weighted average share price of $54.27 in the 2010 period.
Note H – Income Taxes
The Company’s effective income tax rate generally exceeds the statutory U.S. tax rate of 35.0%. The effective tax rate is calculated as the amount of income tax expense divided by income before income tax expense. For the three-month periods in 2011 and 2010, the Company’s effective income tax rates were as follows:
Three months ended March 31
The effective tax rates for the periods presented exceeded the U.S. statutory tax rate of 35.0% due to several factors, including: the effects of income generated in foreign tax jurisdictions; U.S. state tax expense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are available or are not presently being recorded due to a lack of reasonable certainty of adequate future revenue against which to utilize these expenses as deductions.
The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. As of March 31, 2011, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2007; Canada – 2006; United Kingdom – 2009; and Malaysia – 2006.
In March 2011, the United Kingdom announced that the supplemental tax rate for oil and gas companies would be raised later in the year, with an effective date of March 24, 2011. The total tax rate is expected to increase from 50% to 62% for oil and gas companies. The Company will record the effect of this tax increase in its consolidated financial statements when the rate increase is officially enacted, which is currently anticipated in June or July 2011. Based on the Company’s current understanding of the anticipated rate increase, the estimated effect will be an increase in 2011 tax expense of approximately $19 million. The majority of this effect relates to an adjustment to increase the carrying value of net deferred tax liabilities associated with U.K. upsteam operations.
Note I – Financial Instruments and Derivatives
Murphy periodically utilizes derivative instruments to manage certain risks related to commodity prices and foreign currency exchange rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges. The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated any derivative contracts as hedges, and therefore, it recognizes all gains and losses on derivative contracts in its Consolidated Income Statement.
Commodity Purchase Price Risks – The Company is subject to commodity price risks related to crude oil feedstocks it holds in inventory at its refineries. Short-term derivative instruments were outstanding at March 31, 2011 to manage the cost of about 0.1 million barrels of crude oil feedstocks at the Company’s U.S. refineries.
10
Note I – Financial Instruments and Derivatives (Contd.)
The total impact of marking to market these contracts decreased income before taxes by $0.4 million in the three-month period ended March 31, 2011. Additionally, there was an accounts payable of $5.0 million related to matured but unsettled crude oil derivative contracts at March 31, 2011. There were no open crude oil purchase derivative contracts at March 31, 2010.
The Company is also subject to commodity price risk related to corn that it will purchase in the future for feedstock at its ethanol production facilities in the United States. At March 31, 2011 and 2010, the Company had open physical delivery fixed-price purchase commitment contracts for approximately 7.6 million and 0.8 million bushels of corn, respectively, for processing at its ethanol plants. The Company also had outstanding derivative contracts to sell a similar volume of these fixed-priced quantities and buy them back at future prices in effect on the expected date of delivery under the purchase commitment contracts. The impact of marking to market these corn commodity derivative contracts increased income before taxes by $1.8 million in the three-month period ended March 31, 2011 and was insignificant in the three-month period ended March 31, 2010.
Foreign Currency Exchange Risks – The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. Short-term derivative instruments were outstanding at March 31, 2011 and 2010 to manage the risk of certain income tax payments due in 2010 and later years that are payable in Malaysian ringgits. The equivalent U.S. dollars of Malaysian ringgit derivative contracts open at March 31, 2011 and 2010 were approximately $405 million and $361 million, respectively. Short-term derivative instrument contracts totaling $27.0 million and $45.0 million U.S. dollars were also outstanding at March 31, 2011 and 2010, respectively, to manage the risk of certain U.S. dollar accounts receivable associated with sale of crude oil production in Canada. The impact from marking to market these foreign currency derivative contracts increased income before taxes by $12.4 million and $14.3 million at March 31, 2011 and 2010, respectively.
The Company has marked to market each of these open commodity and foreign currency exchange derivative contracts as well as the corn fixed-price purchase commitment contracts. The financial statement impacts for the respective periods are included in the following tables.
At March 31, 2011 and December 31, 2010, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.
Type of Derivative Contract
Commodity
Foreign exchange
For the three-month period ended March 31, 2011 and 2010, the gains and losses recognized in the consolidated statements of income for derivative instruments not designated as hedging instruments are presented in the following table.
Note J – Fair Value Measurements
The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheet. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.
11
Note J – Fair Value Measurements (Contd.)
The carrying value of assets and liabilities recorded at fair value on a recurring basis at March 31, 2011 and December 31, 2010 are presented in the following table.
Assets
Foreign exchange derivative contracts
Commodity derivative contracts
Liabilities
Nonqualified employee savings plans
The fair value of commodity derivative contracts was determined based on market quotes for West Texas Intermediate crude oil and for No. 2 yellow corn. The fair value of foreign exchange derivative contracts was based on market quotes for similar contracts at the balance sheet date. The income effect of changes in fair value of commodity derivative contracts is recorded in Crude Oil and Product Purchases in the Consolidated Statement of Income and changes in fair value of foreign exchange derivative contracts is recorded in Interest and Other Income. The nonqualified employee savings plan is an unfunded savings plan through which the participants seek a return via phantom investments in equity securities and/or mutual funds. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. The income effect of changes in the fair value of nonqualified employee savings plan is recorded in Selling and General Expense.
Note K – Accumulated Other Comprehensive Income
The components of Accumulated Other Comprehensive Income on the Consolidated Balance Sheets at March 31, 2011 and December 31, 2010 are presented net of taxes in the following table.
Foreign currency translation gains
Retirement and postretirement benefit plan losses
Note L – Environmental and Other Contingencies
The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax increases and retroactive tax claims; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Because governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences, and may be taken in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.
12
Note L – Environmental and Other Contingencies (Contd.)
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. 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 the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result.
The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws the Company 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, the Company is investigating the extent of any such liability and the availability of applicable defenses and believes 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.
The Company’s liability for remedial obligations includes certain amounts that are based on anticipated regulatory approval for proposed remediation of former refinery waste sites. Although regulatory authorities may require more costly alternatives than the proposed processes, the cost of such potential alternative processes is not expected to exceed the accrued liability by a material amount. Certain environmental expenditures are likely to be recovered by the Company from other sources, primarily environmental funds maintained by certain states. Since no assurance can be given that future recoveries from other sources will occur, the Company has not recorded a benefit for likely recoveries.
The U.S. Environmental Protection Agency (EPA) currently considers the Company to be a Potentially Responsible Party (PRP) at one Superfund site. The potential total cost to all parties to perform necessary remedial work at the one remaining Superfund site may be substantial. However, based on current negotiations and available information, the Company believes that it is a de minimis party as to ultimate responsibility at this Superfund site. The Company has not recorded a liability for remedial costs on Superfund sites. The Company could be required to bear a pro rata share of costs attributable to nonparticipating PRPs or could be assigned additional responsibility for remediation at the site or other Superfund sites. The Company believes that its share of the ultimate costs to clean-up the Superfund site will be immaterial and will not have a material adverse effect on its net income, financial condition or liquidity in a future period.
There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.
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 insurance coverage issues will not have a material adverse effect on its net income, financial condition or liquidity in a future period.
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 these matters is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
13
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. At March 31, 2011, the Company had contingent liabilities of $7.8 million under a financial guarantee and $72.4 million on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to these letters of credit because it is believed that the likelihood of having these drawn is remote.
Note M – Commitments
The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2011 and 2012 natural gas sales volumes in the Tupper area in Western Canada. The contracts call for natural gas deliveries of approximately 54 million cubic feet per day in the second quarter of 2011 at an average price of Cdn$5.45 per MCF, with the contracts calling for delivery at the AECO “C” sales point. In the last six months of 2011, contracts call for delivery of approximately 74 million cubic feet per day at an average price of Cdn$5.08 per MCF. In 2012, contracts call for delivery of approximately 25 million cubic feet per day at an average price of Cdn$4.35 per MCF. These contracts have been accounted for as a normal sale for accounting purposes.
Note N – Terra Nova Working Interest Redetermination
The joint agreement between the owners of the Terra Nova field, offshore Eastern Canada, requires a redetermination of working interests based on an analysis of reservoir quality among fault separated areas where varying ownership interests exist. The Terra Nova redetermination process was essentially completed in 2010, and the Company’s working interest at Terra Nova was reduced from its original 12.0% to approximately 10.475%. The Company made a cash settlement payment in the first quarter 2011 to certain Terra Nova partners for the value of oil sold since February 2005 related to the working interest reduction. The Company had recorded cumulative expense of $102.1 million through 2010 based on the working interest reduction. Based on the final settlement paid in 2011, the Company recorded a benefit of $5.4 million in the first quarter of 2011 due to the ultimate cost of the redetermination settlement being less than originally estimated. The expense and benefit have been reflected as Redetermination of Terra Nova Working Interest in the Consolidated Statements of Income.
Note O – Accounting Matters
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 amended 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 expanded 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 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 has sought 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 Dodd-Frank Act.
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Note P – Business Segments
(Millions of dollars)
Exploration and production*
United States
Canada
Malaysia
United Kingdom
Republic of the Congo
Other
Refining and marketing
United States manufacturing
United States marketing
Total operating segments
Corporate and other
United States Manufacturing operations include two refineries and two ethanol production facilities. The Company acquired an unfinished ethanol production facility in Hereford, Texas, in the third quarter 2010; construction of the plant was completed and start-up and commissioning commenced at the end of March 2011. United States Marketing includes retail and wholesale fuel marketing operations. Transactions between these two U.S. downstream segments are recorded at agreed transfer prices, which approximate market value, and eliminations have been made as necessary within the consolidated financial statements. The Company previously announced its intention to sell its two U.S. refineries and its U.K. downstream operations during 2011. The Company expects that the results of these operations to be sold 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.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Results of Operations
Murphy’s net income in the first quarter of 2011 was $268.9 million ($1.38 per diluted share) compared to net income of $148.9 million ($0.77 per diluted share) in the first quarter of 2010. The income improvement in 2011 primarily related to higher sales prices for the Company’s crude oil production, higher earnings from U.S. refining operations, and lower losses for transactions denominated in foreign currencies.
Murphy’s income by type of business is presented below.
Exploration and production
Corporate
In the 2011 first quarter, the Company’s exploration and production operations earned $260.4 million compared to $247.0 million in the 2010 quarter. Income in the 2011 quarter was favorably impacted by higher crude oil sales prices and a record level of natural gas sales volumes compared to 2010. However, crude oil sales levels in 2011 were below 2010, North American natural gas sale prices in 2011 were weaker than in 2010 and exploration expenses were higher in the first quarter of 2011 compared to the same period of 2010. The Company’s refining and marketing operations generated income of $30.7 million in the 2011 first quarter compared to a loss of $29.7 million in the same quarter of 2010. The most significant improvement in downstream came from U.S. manufacturing operations, which had higher earnings in the 2011 quarter due to better refining margins and a record volume of oil throughput through the U.S. refineries. Results for the U.K. downstream segment improved in 2011 due to a stronger refining margin coupled with record throughputs at the Milford Haven refinery. The corporate function had after-tax costs of $22.2 million in the 2011 first quarter compared to costs of $68.4 million in the 2010 period with the favorable variance in 2011 primarily due to lower expenses associated with transactions denominated in foreign currencies.
Exploration and Production
Results of exploration and production operations are presented by geographic segment below.
Other International
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (Contd.)
Exploration and Production (Contd.)
In the United States, exploration and production operations had income of $16.5 million in the first quarter of 2011 compared to $18.7 million in the 2010 quarter. This unfavorable result in 2011 compared to the prior year was primarily due to higher exploration expenses. Earnings in the 2011 quarter benefited from higher crude oil sale prices, higher natural gas sales volumes and lower depreciation expense. Other unfavorable variances for 2011 included lower oil sales volumes, lower sales prices for natural gas and higher expenses for production and administration. Production expense in the U.S. was higher in the 2011 period compared to 2010 due to more significant production activities in the Eagle Ford Shale area of South Texas. Depreciation expense declined in 2011 primarily due to lower overall production volumes and lower unit rates for capital amortization. Exploration expense in the U.S. of $40.8 million was up $12.8 million in 2011 due to higher seismic acquisition costs in the Gulf of Mexico and Eagle Ford Shale area and higher amortization expense for undeveloped leases held in the Eagle Ford Shale area.
Earnings from operations in Canada were $86.4 million in the 2011 quarter compared to $49.2 million in the 2010 quarter. Canadian operations realized higher crude oil sales prices and higher sales volumes for oil and natural gas. The 2011 period had unfavorable variances for lower natural gas sales prices and higher expenses related to production, depreciation and exploration activities. The 2011 quarter benefited from a $5.4 million credit to true-up the final settlement cost related to the redetermination of working interest at the Terra Nova field, offshore Newfoundland. The Company’s working interest at Terra Nova was reduced from 12.0% to 10.475% and a cash settlement paid in early 2011 was less than originally estimated. The 2010 period had costs of $5.5 million associated with the Terra Nova field redetermination. Natural gas sales volumes were higher in the 2011 quarter due to start-up of production operations at the Tupper West area in Western Canada in February 2011. Production expenses in Canada were unfavorable in 2011 due to higher costs at Syncrude and start-up of natural gas production at Tupper West. Depreciation expense increased in the 2011 period compared to 2010 due mostly to the Tupper West natural gas sales volumes and higher unit rates at Syncrude. Exploration expenses in Canada were $8.7 million in 2011 compared to $7.4 million in 2010, and the increase was due primarily to higher geophysical costs incurred in 2011 at properties in Southern Alberta.
Operations in Malaysia reported a profit of $195.8 million in the first quarter of 2011 compared to a profit of $173.5 million in the same period in 2010. The 2011 results were favorable to 2010 primarily due to higher crude oil sales prices. In addition, natural gas sales volumes and prices were higher during the 2011 period at fields offshore Sarawak. Crude oil liquids production and sales volumes declined during the 2011 period, primarily due to lower gross volumes produced at the Kikeh field. Several Kikeh wells were off production during a portion of the 2011 period; workovers were ongoing at certain of these wells, which led to higher production expense during the 2011 quarter. Depreciation expense in Malaysia was lower in 2011 mostly due to less Kikeh field production in the current period. Exploration expense was minimal in the 2011 quarter compared to $22.8 million in 2010 as the prior year’s quarter had unsuccessful wildcat drilling costs in deepwater blocks offshore Sabah. Certain exploration expenses in Malaysia do not receive income tax benefits at the present time.
U.K. operations earned $9.0 million in the 2011 period versus $16.6 million in the same quarter a year ago, with the reduction primarily due to lower crude oil sales volumes. The 2010 quarter had higher sales volumes at the Schiehallion field, where sales in late 2009 had been delayed due to damage to an export hose. Production and depreciation expenses in 2011 were below 2010 levels in the U.K. due to lower oil and gas sales volumes.
Operations in Republic of the Congo had income of $3.6 million in the first quarter of 2011 compared to income of $2.5 million in the comparable 2010 quarter. Income improved in the current period primarily due to higher crude oil sales prices and higher crude oil sales volumes. Depreciation expense increased in 2011 associated with the higher crude oil sales volumes and a higher unit rate for capital amortization. Production expense declined in 2011 versus 2010 due to more stable operations at the Azurite field. Exploration expense increased in 2011 compared to 2010 due to final dry hole costs in the just completed quarter for unsuccessful wells that were drilled in the second half of 2010 in the MPS block.
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Other international operations reported a loss of $50.9 million in the 2011 period versus a loss of $13.5 million in the same period for 2010. The higher loss in 2011 was primarily due to unsuccessful exploratory drilling costs in the current quarter for two wells offshore Suriname. The 2011 quarter also included higher lease amortization and other exploratory costs associated with a recently signed license in the Central Dohuk area in the Kurdistan region of Iraq. Geophysical costs were lower in 2011 as the prior year included costs for studies in Indonesia.
On a worldwide basis, the Company’s crude oil, condensate and natural gas liquids sales price averaged $86.73 per barrel for the 2011 first quarter compared to $64.89 per barrel realized in the first quarter of 2010. The Company’s total production averaged 182,152 barrels of oil equivalent per day during the first quarter 2011 compared to 196,226 barrels per day in the 2010 first quarter. Crude oil and liquids production averaged 113,313 barrels per day in the 2011 quarter, down from the 139,060 barrels per day produced in the 2010 period. The primary decline in oil production in the 2011 period occurred in Malaysia due to lower gross production at Kikeh field. Certain key wells at Kikeh were shut-in during a portion of the 2011 quarter for ongoing equipment workovers. Oil production in the United States was lower in 2011 than 2010 due to production decline at fields in the Gulf of Mexico primarily caused by an inability to obtain drilling permits from U.S. government regulators following the Macondo incident in 2010. Heavy oil production in Western Canada increased in the 2011 first quarter compared to the 2010 period primarily due to an increase in producing wells in the Seal area. Production volumes offshore Eastern Canada were lower in 2011 compared to 2010 primarily due to lower gross production at Terra Nova. Synthetic net oil production at Syncrude in northern Alberta increased in 2011 compared to 2010 primarily due to higher gross production. Production in the U.K. in 2011 was unfavorable compared to 2010 due to lower volumes produced at the Mungo/Monan fields caused by equipment downtime. Oil production from the Azurite field in Republic of the Congo in the first quarter 2011 was higher than the same quarter of 2010 due to additional wells on stream in the current year. Average oil sales volumes decreased from 145,783 barrels per day in the 2010 first quarter to 112,804 barrels per day in 2011. The lower crude oil sales volumes were attributable to reduced volumes sold at the Kikeh field in Malaysia and in the U.K. and U.S. North American natural gas sales prices averaged $4.35 per thousand cubic feet (MCF) in the 2011 first quarter compared to $5.14 per MCF realized in the same quarter of 2010. Total natural gas sales volumes averaged 413 million cubic feet per day in 2011, an increase from the 343 million cubic feet per day sold in the same period of 2010. The increase in 2011 was primarily attributable to several areas, including new natural gas production that commenced in February 2011 at the Tupper West area in Western Canada, plus higher natural gas volumes produced at the nearby Tupper Main area, at offshore gas fields in Sarawak and Kikeh in Malaysia, and at the Mondo NW field in the Gulf of Mexico.
Additional details about results of oil and gas operations are presented in the tables on page 20.
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Selected operating statistics for the three-month periods ended March 31, 2011 and 2010 follow.
Net crude oil, condensate and gas liquids produced – barrels per day
Canada – light
– heavy
– offshore
– synthetic
Net crude oil, condensate and gas liquids sold – barrels per day
Net natural gas sold – thousands of cubic feet per day
Malaysia – Sarawak
– Kikeh
Total net hydrocarbons produced – equivalent barrels per day (1)
Total net hydrocarbons sold – equivalent barrels per day (1)
Weighted average sales prices
Crude oil, condensate and natural gas liquids – dollars per barrel (2)
Canada (3) – light
Malaysia (4)
Natural gas – dollars per thousand cubic feet
United States (2)
Canada (3)
United Kingdom (3)
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OIL AND GAS OPERATING RESULTS (unaudited)
Three Months Ended March 31, 2011
Oil and gas sales and other operating revenues
Production expenses
Accretion of assets retirement obligations
Exploration expenses
Dry holes
Geological and geophysical
Undeveloped lease amortization
Total exploration expenses
Terra Nova working interest redetermination
Results of operations before taxes
Income tax provisions
Results of operations (excluding corporate overhead and interest)
Three Months Ended March 31, 2010
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Refining and Marketing
In 2010, the Company announced its intention to sell its three refineries and U.K. marketing operations during 2011. The sale process is ongoing.
United States Manufacturing operations include two refineries and two ethanol production facilities. United States Marketing includes retail and wholesale fuel marketing operations. Transactions between these two U.S. downstream segments are recorded at agreed market-based transfer prices and eliminations have been made as necessary within the consolidated financial statements. The United Kingdom refining and marketing segment includes the Milford Haven, Wales, refinery and all U.K. retail and other refined products marketing operations.
Manufacturing
Marketing
Total – United States
United States manufacturing operations generated a profit of $28.7 million in the 2011 first quarter compared to a loss of $23.6 million during the first quarter of 2010. The favorable result in 2011 was primarily due to stronger U.S. refining margins, which improved by more than $7.00 per barrel in the first quarter of the current year. Additionally, crude oil and other feedstock throughput volumes at U.S. refineries were a quarterly record of 169,217 barrels per day during the 2011 period. The 2010 quarter included lower than normal throughput volumes primarily due to the effects of a six-week complete plant turnaround at the Meraux, Louisiana, refinery. An ethanol production facility in Hankinson, North Dakota, that was acquired in October 2009, was less profitable in the first quarter 2011 than in 2010 due to higher costs of corn feedstocks which outpaced the increase in ethanol sales prices in the later period. An unfinished ethanol plant acquired in 2010 at Hereford, Texas, was completed and start-up and commissioning of the plant commenced at the end of the first quarter 2011.
United States marketing operations generated income of $10.7 million in the three months ended March 31, 2011, compared to income of $8.9 million in the 2010 period. The favorable result in the 2011 quarter was primarily due to U.S. retail marketing margins which improved by about $0.01 per gallon compared to the same period in 2010. In addition, these U.S. retail operations generated higher profits from merchandise sales in 2011. However, overall fuel sales volumes in the later period for the retail operations were below 2010 levels.
Refining and marketing operations in the United Kingdom had a loss of $8.7 million in the first quarter of 2011 compared to a loss of $15.0 million in the same quarter of 2010. The U.K. results in 2011 were favorably affected by improved refining margins and record quarterly throughputs of 124,967 barrels per day at the Milford Haven, Wales, refinery. Crude throughput volumes at the Milford Haven refinery were significantly below normal levels in the 2010 quarter as the plant was shut down for turnaround starting in March 2010. The plant came back onstream in May 2010. A capital project completed during the 2010 turnaround expanded the crude oil throughput capacity of the refinery from 108,000 to 135,000 barrels per day.
Worldwide refinery inputs were a quarterly record of 294,184 barrels per day in the first quarter of 2011 compared to 169,600 barrels per day in the 2010 quarter. The increase in refinery inputs in 2011 was primarily due to turnarounds in the 2010 first quarter at both the Meraux and Milford Haven refineries. Petroleum product sales were 564,335 barrels per day in the 2011 quarter, up from 478,692 barrels per day a year ago. This increase was also mostly due to the aforementioned refinery turnarounds at Meraux and Milford Haven during the prior-year first quarter.
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Refining and Marketing (Contd.)
Refinery inputs – barrels per day
Crude oil – Meraux, Louisiana
– Superior, Wisconsin
Other feedstocks
Crude oil – Milford Haven, Wales
Refinery yields – barrels per day
Gasoline
Kerosine
Diesel and home heating oils
Residuals
Asphalt, LPG and other
Fuel and loss
Petroleum products sold – barrels per day
Total United States
United States Manufacturing
United States Marketing
Diesel and other
United States Intercompany Elimination
LPG and other
Unit margins per barrel:
United States refining1
United Kingdom refining and marketing
United States retail marketing:
Fuel margin per gallon2
Gallons sold per store month
Merchandise sales revenue per store month
Merchandise margin as a percentage of merchandise sales
Store count at end of period (Company operated)
Represents refinery sales realizations less cost of crude and other feedstocks and refinery operating and depreciation expenses.
Represents net sales prices for fuel less purchased cost of fuel.
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Corporate activities, which include interest income and expense, foreign exchange effects, and corporate overhead not allocated to operating functions, had net costs of $22.2 million in the 2011 first quarter compared to net costs of $68.4 million in the first quarter of 2010. The results for corporate activities were favorable in 2011 compared to 2010 primarily due to after-tax losses of $1.1 million in the 2011 quarter on transactions denominated in foreign currencies compared to after-tax losses of $41.3 million in the 2010 quarter. The foreign exchange loss in 2010 was primarily associated with a stronger U.S. dollar compared to the British sterling and a weaker U.S. dollar compared to the Malaysian ringgit. The weaker British sterling in 2010 led to foreign currency losses on dollar based liabilities in the sterling functional U.K. downstream operations, and the stronger Malaysian ringgit led to foreign currency losses on ringgit based income tax liabilities in the dollar functional Malaysian oil and gas operations. The 2011 first quarter also had lower net interest expense compared to 2010 mainly due to a combination of lower average debt levels and higher amounts of interest capitalized to oil and gas development projects.
Financial Condition
Net cash provided by operating activities was $522.9 million for the first three months of 2011 compared to $829.4 million during the same period in 2010. Changes in operating working capital other than cash and cash equivalents used cash of $140.4 million in the first quarter of 2011, but generated cash of $244.3 million in the first quarter of 2010. Working capital used cash in the 2011 quarter due to an increase in accounts receivable from customers caused by higher sales prices, which outpaced the increase in accounts payable primarily caused by higher amounts owed on crude oil purchases by the Company’s refineries. The cash generated from working capital changes in the 2010 quarter essentially related to a $244.4 million recovery of U.S. federal royalties paid in prior years. Cash of $587.8 million and $513.6 million in the 2011 and 2010 quarters, respectively, was generated from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition.
Significant uses of cash in both years were for dividends, which totaled $53.1 million in 2011 and $47.8 million in 2010, and for property additions and dry holes, which, including amounts expensed, were $526.8 million and $481.0 million in the three-month periods ended March 31, 2011 and 2010, respectively. Additionally, cash of $428.3 million and $630.2 million was used to purchase Canadian government securities with maturity dates greater than 90 days during the three months ended March 31, 2011 and 2010, respectively. The Company expended $50.5 million on major repairs in the 2010 period due to planned major turnarounds at the Meraux, Louisiana, and Milford Haven, Wales, refineries during the period. Total capital expenditures on an accrual basis were as follows:
Capital expenditures
Total capital expenditures
Working capital (total current assets less total current liabilities) at March 31, 2011 was $740.5 million, an increase of $120.7 million from December 31, 2010. This level of working capital does not fully reflect the Company’s liquidity position, because the lower historical costs assigned to inventories under last-in first-out accounting were $950.3 million below fair value at March 31, 2011.
At March 31, 2011, total long-term debt of $974.4 million had increased by $35.0 million compared to December 31, 2010. A summary of capital employed at March 31, 2011 and December 31, 2010 follows.
Capital employed
Total capital employed
The Company’s ratio of earnings to fixed charges was 25.0 to 1 for the three-month period ended March 31, 2011.
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Accounting and Other Matters
Outlook
Average crude oil prices in April 2011 remained above the average prices during the first quarter 2011. U.S. downstream margins in April 2011 have been generally weaker than those experienced in the first quarter. The Company expects its oil and natural gas production to average about 187,000 barrels of oil equivalent per day in the second quarter 2011, while sales volumes are expected to average approximately 180,000 barrels of oil equivalent per day during the quarter. Production volumes are projected to be higher in the second quarter 2011 than in the first quarter primarily due to continued ramp-up of natural gas production in the Tupper West area of Western Canada. The Company anticipates total production volumes for the full year of 2011 to average 200,000 barrels of oil equivalent per day. The Company currently anticipates total capital expenditures for the full year 2011 to be approximately $3.0 billion.
Forward-Looking Statements
This Form 10-Q 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 Murphy’s 2010 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission. Murphy undertakes no duty to publicly update or revise any forward-looking statements.
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ITEM 3. 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 I to this Form 10-Q report, Murphy periodically makes 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 March 31, 2011 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 purchase commitments of 7.6 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 a similar volume 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 prices of these commodities would have reduced the recorded net asset associated with these commodity contracts by approximately $0.2 million, while a 10% decrease would have increased the recorded net 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 March 31, 2011 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 asset associated with these contracts by approximately $50.2 million, while a 10% weakening of the U.S. dollar would have increased the recorded asset by approximately $40.4 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 4. CONTROLS AND PROCEDURES
Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company 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 the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, 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) are 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.
There have been no changes in the Company’s internal control over financial reporting during the quarter ended March 31, 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
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 environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
ITEM 1A. RISK FACTORS
The Company has not identified any additional risk factors not previously disclosed in its Form 10-K report filed on February 28, 2011.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
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SIGNATURE
Pursuant to the requirements 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.
(Registrant)
By
/s/ JOHN W. ECKART
John W. Eckart, Vice President and Controller
(Chief Accounting Officer and Duly Authorized Officer)
May 6, 2011
(Date)
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EXHIBIT INDEX
Exhibit
No.
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.”
Exhibits other than those listed above have been omitted since they are either not required or not applicable.
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