UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
For the quarterly period ended September 30, 2010
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 September 30, 2010 was 192,366,738.
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 from continuing operations before income taxes
Income tax expense
Income from continuing operations
Income from discontinued operations, net of income taxes
NET INCOME
INCOME PER COMMON SHARE – BASIC
Income from discontinued operations
Net income – Basic
INCOME PER COMMON SHARE – DILUTED
Net income – Diluted
Average common shares outstanding – basic
Average common shares outstanding – diluted
See Notes to Consolidated Financial Statements, page 7.
The Exhibit Index is on page 33.
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 $8,081 in 2010 and $7,761 in 2009
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 $5,665,235 in 2010 and $4,714,826 in 2009
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 192,835,791 shares in 2010 and 191,797,600 shares in 2009
Capital in excess of par value
Retained earnings
Accumulated other comprehensive income
Treasury stock, 469,053 shares of Common Stock in 2010 and 682,222 shares of Common Stock in 2009, at cost
Total stockholders’ equity
Total liabilities and stockholders’ equity
3
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)
Net income
Other comprehensive income, net of tax
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
Pretax gain from disposition of assets
Net (increase) decrease in noncash operating working capital
Other operating activities, net
Net cash provided by continuing operations
Net cash required by discontinued operations
Net cash provided by operating activities
INVESTING ACTIVITIES
Property additions and dry hole costs
Proceeds from sales of assets
Purchase of investment securities*
Proceeds from maturity of investment securities*
Expenditures for major repairs
Other – net
Investing activities of discontinued operations
Sales proceeds
Other
Net cash required by investing activities
FINANCING ACTIVITIES
Borrowings (repayments) of long-term debt
Repayment of nonrecourse debt of a subsidiary
Proceeds from exercise of stock options and employee stock purchase plans
Excess tax benefits related to exercise of stock options
Withholding tax on stock-based incentive awards
Cash dividends paid
Net cash provided (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 September 30
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 192,835,791 at September 30, 2010 and 191,626,348 shares at September 30, 2009
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
Restricted stock transactions and other
Stock-based compensation
Sale of stock under employee stock purchase plans
Retained Earnings
Net income for the period
Cash dividends
Accumulated Other Comprehensive Income (Loss)
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
Cancellation of performance-based restricted stock and 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, 2009. 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 September 30, 2010, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 2010 and 2009, 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 2009 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 and nine-month periods ended September 30, 2010 are not necessarily indicative of future results.
Note B – Discontinued Operations
On March 12, 2009, the Company sold its operations in Ecuador for net cash proceeds of $78.9 million, subject to post-closing adjustments. The acquirer also assumed certain tax and other liabilities associated with the Ecuador properties sold. These properties included 20% interests in producing Block 16 and the nearby Tivacuno area. The Company recorded a gain of $103.6 million, net of income taxes of $14.0 million, from the sale of the Ecuador properties in 2009. At the time of the sale, the Ecuador properties produced approximately 6,700 net barrels per day of heavy oil and had net oil reserves of approximately 4.3 million barrels. All 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 were as follows:
Property, plant and equipment, net of accumulated depreciation, depletion and amortization
Other noncurrent assets
Assets sold
Other noncurrent liabilities
Liabilities associated with assets sold
The following table reflects the results of operations during 2009 from the sold properties, including the gain on sale.
Revenues, including a pretax gain on sale of $117,557
Income before income tax expense
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C – 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 September 30, 2010, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $459.7 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2010 and 2009.
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 September 30
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 $376.0 million of exploratory well costs capitalized more than one year at September 30, 2010, $237.4 million is in Malaysia, $104.8 million is in the U.S., $14.9 million is in Republic of the Congo, $9.5 million is in the U.K., and $9.4 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 and in the U.K. further studies to evaluate the discovery are ongoing.
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 essentially encompassed within the U.S. manufacturing and U.K. refining and marketing segments presented in Note R. 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.
In August 2010, the Company purchased an unfinished ethanol plant in Hereford, Texas, for $40 million. The Company expects the construction of the plant to be completed and the plant to be in operation by the end of the first quarter of 2011. The allocation of the purchase price to the assets, which include land, buildings and equipment, will be finalized in the fourth quarter 2010.
8
Note D – 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 September 30, 2010 and December 31, 2009, the carrying value of inventories under the LIFO method was $612.1 million and $551.2 million, respectively, less than such inventories would have been valued using the first-in, first-out (FIFO) method.
Note E – 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, net of amounts capitalized
Note F – 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 and nine-month periods ended September 30, 2010 and 2009.
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
9
Note F – Employee and Retiree Benefit Plans (Contd.)
Special termination benefits expense
Curtailment expense
Special termination and curtailment expenses in the nine-month 2009 period related to an early retirement program for certain employees in the United States.
During the nine-month period ended September 30, 2010, the Company made contributions of $18.8 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2010 for the Company’s defined benefit pension and postretirement plans is anticipated to be $8.3 million.
In March 2010, the U.S. 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) imposes 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 September 30, 2010 and for the three-month and nine-month periods then ended. The Company is still evaluating the various components of the new law and cannot predict with certainly 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 G – 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.
10
Note G – Incentive Plans (Contd.)
In February 2010, the Committee granted stock options for 1,605,628 shares at an exercise price of $52.845 per share. The Black-Scholes valuation for these awards was $18.75 per option. The Committee also granted 449,100 performance-based restricted stock units in February 2010 under the 2007 Long-Term Plan. The fair value of the performance-based restricted stock units, using a Monte Carlo valuation model, ranged from $42.38 to $50.95 per unit. Also in February the Committee granted 43,370 shares of time-lapse 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 $52.49 per share.
Cash received from options exercised under all share-based payment arrangements for the nine-month periods ended September 30, 2010 and 2009 was $26.1 million and $8.6 million, respectively. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $11.7 million and $3.5 million for the nine-month periods ended September 30, 2010 and 2009, 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
Note H – Earnings per Share
Net income was used as the numerator in computing both basic and diluted income per Common share for the three-month and nine-month periods ended September 30, 2010 and 2009. The following table reconciles the weighted-average shares outstanding used for these computations.
Basic method
Dilutive stock options and restricted stock units
Diluted method
Certain options to purchase shares of common stock were outstanding during the 2010 and 2009 periods but were not included in the computation of diluted EPS because the incremental shares from assumed conversion were antidilutive. These included 2,237,753 shares at a weighted average share price of $58.79 in each 2010 period and 1,872,625 shares at a weighted average share price of $56.74 in each 2009 period.
Note I – Income Taxes
The Company’s effective income tax rate generally exceeds the statutory U.S. tax rate of 35%. The effective tax rate is calculated as the amount of income tax expense divided by income before income tax expense. For the three-month and nine-month periods in 2010 and 2009, the Company’s effective income tax rates were as follows:
Three months ended September 30
Nine months ended September 30
11
Note I – Income Taxes (Contd.)
The effective tax rates for the periods presented exceeded the U.S. statutory tax rate of 35% 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 tax rate for the nine-month period in 2010 benefited 0.5% for an income tax adjustment in the U.K. Additionally, an enacted 1% tax rate reduction in the U.K. effective in April 2011 reduced the effective tax rate in the three-month and nine-month periods of 2010 by 0.5% and 0.2%, respectively.
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 September 30, 2010, 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 – 2007; and Malaysia – 2006.
Note J – 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 and intermediate feedstocks it holds in inventory at its refineries. Short-term derivative instruments were outstanding at September 30, 2010 and 2009 to manage the cost of about 0.9 million barrels and 0.6 million barrels, respectively, of crude oil feedstocks at the Company’s U.S. refineries. At September 30, 2010, the Company also had open derivative contracts covering 0.4 million barrels of inventories of intermediate feedstocks to be processed at these refineries.
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 facility in Hankinson, North Dakota. At September 30, 2010, the Company had open physical delivery fixed-price purchase commitment contracts for approximately 5.4 million bushels of corn for processing at its ethanol plant. The Company also had outstanding derivative contracts to sell an equivalent 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.
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 September 30, 2010 and 2009 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 September 30, 2010 and 2009 were approximately $194.0 million and $100.0 million, respectively. Short-term derivative instruments were also outstanding at September 30, 2010 and 2009 to manage the risk of certain U.S. dollar accounts receivable associated with sale of crude oil production in Canada. A total of $107.0 million and $22.0 million U.S. dollar contracts were outstanding at September 30, 2010 and 2009, respectively, related to these Canadian receivables.
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.
12
Note J – Financial Instruments and Derivatives (Contd.)
At September 30, 2010 and December 31, 2009, 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 and nine-month periods ended September 30, 2010 and 2009, 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 K – 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.
The carrying value of assets and liabilities recorded at fair value on a recurring basis at September 30, 2010 and December 31, 2009 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 WTI crude and 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.
13
Note L – Accumulated Other Comprehensive Income
The components of Accumulated Other Comprehensive Income on the Consolidated Balance Sheets at September 30, 2010 and December 31, 2009 are presented in the following table.
Foreign currency translation gains, net of tax
Retirement and postretirement benefit plan losses, net of tax
Note M – 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.
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. In early 2010, the Company’s involvement with another Superfund site was settled for a de minimis cash settlement. 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
14
Note M – Environmental and Other Contingencies (Contd.)
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 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.
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.
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 September 30, 2010, the Company had contingent liabilities of $7.8 million under a financial guarantee and $154.5 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 N – Commitments
The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2010 and 2011 natural gas sales volumes at the Tupper field in Western Canada. The contracts call for natural gas deliveries of approximately 33 million cubic feet per day during the remainder of 2010 at a price of Cdn$5.30 per thousand cubic feet and 34 million cubic feet per day in 2011 at a price of Cdn$6.26, with both contracts calling for delivery at the AECO “C” sales point. These contracts have been accounted for as a normal sale for accounting purposes.
Note O – 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 operator of Terra Nova completed the initial redetermination assessment in 2009 and the matter is the subject of arbitration before final interests are determined. The Company anticipates that its working interest at Terra Nova will be reduced from its current 12.0% to approximately 10.5%. Upon completion of the arbitration process, the Company will be required to make a cash settlement payment to the Terra Nova partnership for the value of oil sold since about December 2004 related to the ultimate working interest reduction below 12.0%. The Company has recorded cumulative expense of $98.9 million through September 2010 based on the anticipated working interest reduction. The expense has been reflected as Redetermination of Terra Nova Working Interest in the respective Consolidated Statement of Income. The Company cannot predict the final outcome of the redetermination process, which is expected to be completed by the end of 2010.
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Note P – 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 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.
Note Q – Insurance Matters
The Company maintains insurance coverage related to property damage, liability, and losses of production and profits for occurrences such as storms, fires and other issues. During the third quarter 2009, certain insurance coverage matters were concluded regarding the crude oil spill that occurred at the Meraux, Louisiana refinery following Hurricane Katrina in 2005, and income of $6.5 million, including interest, was recorded in revenue in the Consolidated Statement of Income during the three-month period ended September 30, 2009. During the second quarter 2009, the Company received insurance proceeds to settle business interruption claims related to downtime following a fire at the Meraux, Louisiana refinery in June 2003. Additionally, other insurance proceeds were received during the second quarter 2009 related to damages at the Meraux refinery caused by Hurricane Katrina in 2005. Total income of $28.4 million was recorded in revenue for the nine-month period ended September 30, 2009 related to these various insurance matters.
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Note R – Business Segments
(Millions of dollars)
Exploration and production2
United States
Canada
Malaysia
United Kingdom
Republic of the Congo
Refining and marketing
United States manufacturing
United States marketing
Total operating segments
Corporate
Revenue/income from continuing operations
Discontinued operations, net of tax
Reclassified to conform to current presentation.
Additional details about results of oil and gas operations are presented in the tables on pages 24 and 25.
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Note R – Business Segments (Contd.)
Due to a recent realignment of management responsibilities within the Company’s domestic downstream business, U.S. refining and marketing operating results have now been presented as separate segments for U.S. manufacturing operations and U.S. marketing operations. The Company believes this presentation better reflects the core businesses of its U.S. downstream subsidiaries. United States Manufacturing operations include two refineries and an ethanol production facility. The Company acquired an unfinished ethanol production facility in Hereford, Texas, in the third quarter 2010; the completion and start-up of this plant is expected by the end of the first quarter 2011. United States Marketing includes retail and wholesale fuel marketing operations. Prior year amounts have been reclassified to reflect the new segment presentation. Transactions between these two U.S. downstream segments are recorded at agreed transfer prices 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.
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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 third quarter of 2010 was $202.8 million ($1.05 per diluted share) compared to net income of $188.9 million ($0.98 per diluted share) in the third quarter of 2009. The income improvement in 2010 primarily related to higher sales prices for the Company’s crude oil and natural gas production, higher crude oil and natural gas sales volumes and higher earnings from U.S. downstream operations.
For the first nine months of 2010, net income totaled $624.0 million ($3.24 per diluted share) compared to net income of $518.8 million ($2.70 per diluted share) for the same period in 2009. The favorable nine-month net income in 2010 compared to 2009 was primarily attributable to higher crude oil sales prices and sales volumes. The 2009 nine-month net income included income from discontinued operations of $97.8 million ($0.51 per diluted share) with this amount primarily being generated from an after-tax gain of $103.6 million on sale of operations in Ecuador in March 2009. Income from continuing operations was $624.0 million ($3.24 per diluted share) in the nine months ended September 30, 2010 and was $421.0 million ($2.19 per diluted share) in the nine months ended September 30, 2009.
Murphy’s income from continuing operations by operating business is presented below.
Exploration and production
In the 2010 third quarter, the Company’s continuing exploration and production operations earned $186.7 million compared to $184.1 million in the 2009 quarter. Income in the 2010 quarter was favorably impacted by higher crude oil and natural gas sales prices and higher natural gas and oil sales volumes compared to 2009. However, exploration expenses were $62.0 million in the third quarter of 2010 compared to $37.9 million in the same period of 2009. The Company’s refining and marketing operations generated income of $50.6 million in the 2010 third quarter compared to income of $37.2 million in the same quarter of 2009. U.S. manufacturing and retail marketing operations had higher earnings in the 2010 quarter, but the 2010 results for the U.K. downstream segment declined due to weaker margins. The corporate function had after-tax costs of $34.5 million in the 2010 third quarter compared to costs of $32.4 million in the 2009 period with the unfavorable variance in 2010 mostly due to higher administrative expenses.
The Company’s continuing exploration and production operations earned $652.8 million in the first nine months of 2010 compared to $352.7 million in the same period of 2009. Earnings in 2010 compared favorably to the 2009 period primarily due to higher realized crude oil sales prices and higher crude oil and natural gas sales volumes. The Company’s refining and marketing operations had earnings of $104.7 million in the first nine months of 2010 compared to earnings of $75.8 million in the same 2009 period. The 2010 period included stronger results in the U.S. retail marketing business compared to a year ago based on better operating margins, but income from refining operations in the U.S. and U.K. were significantly lower in 2010 compared to 2009 due to weaker margins for refining operations and downtime for major turnarounds in 2010 at the Meraux, Louisiana, and Milford Haven, Wales, refineries. Corporate after-tax costs were $133.5 million in the 2010 nine-month period compared to costs of $7.5 million in the 2009 period. The 2010 period had an unfavorable impact from losses on transactions denominated in foreign currencies, while the prior year included gains from these transactions.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (Contd.)
Exploration and Production
Results of exploration and production continuing operations are presented by geographic segment below.
Other International
Third quarter 2010 vs. 2009
United States exploration and production operations reported quarterly earnings of $14.6 million in the third quarter of 2010 compared to earnings of $6.0 million in the 2009 quarter. Earnings improved in the 2010 period due mostly to higher oil and natural gas sales prices. Oil and natural gas production volumes were higher in 2010 primarily due to the Thunder Hawk field, which came on production in the third quarter 2009. But oil and natural gas volume declines at mature fields in the Gulf of Mexico somewhat offset the volumes produced at Thunder Hawk. Depreciation expense was down $13.4 million in 2010 due to lower oil and natural gas production volumes and lower per unit depletion rates in 2010. Exploration expenses in the 2010 period increased $8.0 million from the prior year primarily due to higher seismic acquisition costs and undeveloped leasehold amortization in the Eagle Ford shale area in South Texas.
Operations in Canada had earnings of $39.1 million in the third quarter 2010 compared to earnings of $44.6 million in the 2009 quarter. Canadian earnings decreased in the 2010 quarter mostly due to lower oil sales volumes, higher extraction costs for synthetic operations and higher exploration expense. Oil production decreased in the 2010 period compared to 2009 primarily due to more downtime for maintenance at Syncrude in the current period. Natural gas volumes increased in 2010 mostly due to continued ramp-up of Tupper area production. Production expense was unfavorable in 2010 due primarily to higher maintenance costs during the period for synthetic oil operations at Syncrude. Exploration expenses were $4.5 million higher in the 2010 period primarily due to more leasehold amortization expense for undeveloped oil and gas prospective acreage in Alberta.
Operations in Malaysia reported earnings of $167.6 million in the 2010 third quarter compared to earnings of $156.2 million during the same period in 2009. Earnings rose in 2010 in Malaysia primarily caused by higher crude oil and natural gas sales prices. The 2010 quarter also benefited from higher natural gas sales volumes, which were mostly associated with stronger demand for production from offshore Sarawak gas fields. Oil production was lower in 2010 compared to 2009 due to less production at the Kikeh field, offshore Sabah. Depreciation expense was higher in the 2010 period by $17.3 million due to larger natural gas sales volumes compared to the 2009 quarter.
United Kingdom operations earned $4.9 million in the 2010 quarter compared to $2.1 million in the 2009 quarter. The improvement was primarily due to higher crude oil sales prices in the 2010 quarter compared to 2009. The 2010 quarter also benefited from higher crude oil and natural gas sales volumes and higher realized sales prices for natural gas. Production expense was lower in 2010 than 2009 due to less maintenance costs in the current period, while 2010 depreciation expense exceeded 2009 levels due to higher oil and gas sales volumes.
Operations in Republic of the Congo generated a loss of $20.2 million in the third quarter of 2010 compared to a loss of $11.5 million in the 2009 quarter. The offshore Azurite field commenced oil production in the third quarter of 2009, but the initial oil sale did not occur until quarter four of 2009. Development operations continued at Azurite during 2010 as the Company brought onstream the second producing well during the second quarter of the current year. Due to delays and complications with completing wells, production levels have, thus far, been below Company
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Exploration and Production (Contd.)
expectations at the Azurite field. Production levels at Azurite are expected to ramp-up as additional wells are brought onstream. Expenses for production and depreciation relate to crude oil produced and sold at the Azurite field. Exploration expenses in 2010 primarily included 3D seismic acquired over a portion of the MPS and MPN offshore blocks. Exploration expenses in 2009 primarily related to costs for two unsuccessful exploratory wells in the MPS block. Income taxes during the 2010 quarter related to taxes associated with Azurite production volumes.
Other international operations reported a loss of $19.3 million in the third quarter of 2010 compared to a loss of $13.3 million in the 2009 period. The unfavorable variance in the just completed quarter was primarily related to higher 2010 seismic activity costs in Indonesia as well as higher administrative costs associated with exploration activities in this and other foreign jurisdictions.
On a worldwide basis, the Company’s crude oil, condensate and gas liquids prices averaged $65.45 per barrel in the third quarter 2010 compared to $61.13 in the 2009 period. Total hydrocarbon production averaged 181,733 barrels of oil equivalent per day in the 2010 third quarter, a 12% increase from the 162,004 barrels equivalent per day produced in the 2009 quarter. Average crude oil and liquids production was 119,899 barrels per day in the third quarter of 2010 compared to 131,637 barrels per day in the third quarter of 2009, with the decrease primarily attributable to lower oil production at the Kikeh field, offshore Sabah, Malaysia. Crude oil production in the heavy oil area in Canada was lower in 2010 mostly due to less production in the Seal area caused by a higher royalty rate. Synthetic oil production was lower in the 2010 quarter than 2009 due to lower gross production at Syncrude caused by more downtime for maintenance. North American natural gas sales prices averaged $4.24 per thousand cubic feet (MCF) in the 2010 third quarter compared to $3.01 per MCF in the same quarter of 2009. Natural gas produced in 2010 offshore Sarawak Malaysia was sold at $5.71 per MCF compared to an average of $3.31 per MCF during the 2009 third quarter. Natural gas sales volumes averaged 371 million cubic feet per day in the third quarter 2010, more than double the 182 million cubic feet per day of sales in the 2009 quarter. The significant increase in natural gas sales volumes in 2010 was primarily due to natural gas produced in 2010 offshore Sarawak Malaysia from fields that came on stream in September 2009 and were ramping up over the balance of 2009 and into 2010. Additionally, more natural gas was sold from the Kikeh field to meet third party demand during 2010, and natural gas production increased at Tupper in Western Canada as development of the field continued.
Nine months 2010 vs. 2009
U.S. E&P operations had income of $47.8 million for the nine months ended September 30, 2010 compared to income of $2.6 million in the 2009 period. The 2010 period had higher oil and natural gas sales prices, and also benefited from higher oil sales volumes. Production expenses were $38.2 million higher in 2010 mostly due to higher oil production volumes. Depreciation expense increased $54.6 million in 2010 due to the higher sales volumes plus higher per-unit depletion rates in 2010 compared to 2009. Exploration expense in the 2010 period was $32.4 million above 2009 levels primarily due to higher geophysical expenses and undeveloped lease amortization expenses at the Eagle Ford shale area in South Texas in the current period, partially offset by lower dry hole costs in 2010.
Canadian operations had income of $150.6 million in the first nine months of 2010 compared to income of $38.8 million a year ago. Higher sales prices for crude oil and natural gas, lower exploration expenses and lower charges of $21.0 million in 2010 for an anticipated reduction of the Company’s working interest in the Terra Nova field primarily led to the improvement in 2010 earnings. Production expense increased $24.7 million in 2010 mostly related to higher volumes of natural gas produced at Tupper and higher costs for synthetic crude oil produced at Syncrude. Depreciation expense increased in 2010 by $25.1 million mostly associated with higher production at Tupper and higher unit rates at Syncrude. Exploration expenses were $20.5 million lower in 2010 primarily due to less lease amortization costs at the Tupper West area in British Columbia in the current period.
Malaysia operations earned $499.3 million in the first nine months of 2010 compared to earnings of $400.9 million in the 2009 period. Earnings were stronger in 2010 primarily due to higher crude oil sales prices as well as higher natural gas sales volumes and prices from fields offshore Sarawak. Sales volumes for natural gas were higher in the 2010 period than 2009 due to start-up of natural gas production offshore Sarawak in the third quarter 2009 and higher gas volumes purchased by a third party in 2010 at the Kikeh field. Crude oil sales volumes at the Kikeh field were
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higher in 2010 than 2009 despite overall lower net oil production due to the timing of completion of oil sales transactions. Production and depreciation expenses increased $66.6 million and $78.6 million, respectively, in the 2010 period due to higher oil and natural gas sales volumes. Exploration expense was $17.9 million higher in 2010 mostly due to more costs for unsuccessful exploration drilling in the 2010 period.
Income in the U.K. for the nine-month period in 2010 was $29.9 million compared to $9.1 million a year ago with the earnings increase primarily due to improved crude oil sales prices. In addition, 2010 had higher sales volumes for crude oil and natural gas compared to 2009. Production and depreciation expenses were higher $7.3 million and $10.7 million, respectively, in 2010 compared to 2009 in association with higher oil and natural gas sales volumes. Exploration expenses were higher in the 2010 period due to a dry hole drilled in the third quarter of the current year.
Operations in Republic of the Congo had a loss of $26.6 million for the nine-month period ended September 30, 2010, compared to a loss of $9.4 million in the 2009 period. The offshore Azurite oil field commenced production in the third quarter 2009, but production has thus far been below Company expectations due to delays in completing wells. Production and depreciation expenses incurred in 2010 were associated with the Azurite field. Geophysical costs in the 2010 period were primarily related to 3D seismic acquisition covering a portion of the offshore MPN block. Income taxes during 2010 related to taxes on Azurite production volumes.
Other international operations reported a loss of $48.2 million in the first nine months of 2010 compared to a loss of $89.3 million in the 2009 period. The lower loss in the 2010 period primarily related to costs in 2009 for unsuccessful exploratory drilling offshore Australia and higher geophysical expenses in 2009 offshore Suriname. However, the current year included higher administrative costs related to exploration activities in foreign jurisdictions.
For the first nine months of 2010, the Company’s sales price for crude oil, condensate and gas liquids averaged $65.06 per barrel compared to $52.59 per barrel in 2009. Total worldwide production averaged 189,250 barrels of oil equivalent per day during the nine months ended September 30, 2010, an increase of 23% from the 154,212 barrels of oil equivalent produced in the same period in 2009. Crude oil, condensate and gas liquids production in the first nine months of 2010 averaged 130,244 barrels per day compared to 129,672 barrels per day a year ago. The small increase was mostly attributable to two fields that started up in third quarter 2009 – Thunder Hawk field in the Gulf of Mexico and the Azurite field, offshore Republic of the Congo. The oil production at these two fields was mostly offset by lower production in other areas. Canadian heavy oil production was lower in 2010 than 2009 due to both field decline and a higher net profit royalty rate at the Seal heavy oil field in Alberta. Crude oil production offshore eastern Canada was lower in 2010 primarily due to a higher net profit royalty rate at Terra Nova. Synthetic oil production at Syncrude was higher in 2010 than 2009 due to less downtime in 2010 for maintenance, but partially offset by a higher net profit royalty rate. Crude oil production was lower in 2010 in Malaysia due to a smaller percentage of production being allocable to the Company during 2010 under the production sharing contract covering the Kikeh field. Crude oil volumes from discontinued operations in the prior year were associated with oil fields in Ecuador that were sold in March 2009. The average sales price for North American natural gas in the first nine months of 2010 was $4.48 per MCF, up from $3.50 per MCF realized in 2009. Sarawak field natural gas production was sold at an average price of $5.20 per MCF in 2010, up from $3.31 per MCF in 2009. Natural gas sales volumes increased from 147 million cubic feet per day in 2009 to 354 million cubic feet per day in 2010, with the 140% increase mostly due to continued ramp-up of natural gas production volumes from the Tupper area in British Columbia, which came onstream in December 2008, sales volumes at Sarawak Malaysia gas fields that initially came onstream in the third quarter 2009, and higher sales volumes to third parties from the Kikeh field, offshore Sabah, Malaysia.
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Selected operating statistics for the three-month and nine-month periods ended September 30, 2010 and 2009 follow.
Net crude oil, condensate and gas liquids produced – barrels per day
Continuing operations
Canada – light
– heavy
– offshore
– synthetic
Republic of Congo
Discontinued operations
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 – THREE MONTHS ENDED SEPTEMBER 30, 2010 AND 2009
Three Months Ended September 30, 2010
Oil and gas sales and other operating revenues
Production expenses
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 September 30, 2009*
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OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2010 AND 2009
Nine Months Ended September 30, 2010
Nine Months Ended September 30, 2009*
Income tax provisions (benefits)
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Refining and Marketing
Due to a recent realignment of management responsibilities within the Company’s domestic downstream business, U.S. refining and marketing operating results have now been presented as separate segments for U.S. manufacturing operations and U.S. marketing operations. The Company believes this presentation better reflects the core businesses of its U.S. downstream subsidiaries. United States Manufacturing operations include two refineries and an ethanol production facility. United States Marketing includes retail and wholesale fuel marketing operations. Prior year amounts have been reclassified to reflect the new segment presentation. Transactions between these two U.S. downstream segments are recorded at agreed transfer prices and eliminations have been made as necessary within the consolidated financial statements. 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.
Results of refining and marketing operations are presented below by geographic segment.
The Company’s refining and marketing operations generated income of $50.6 million in the 2010 third quarter compared to earnings of $37.2 million in the same quarter of 2009. United States manufacturing operations had income of $10.2 million in the 2010 period compared to a profit of $1.6 million in 2009. U.S. manufacturing operations had better earnings primarily due to profits at the Company’s Hankinson, North Dakota, ethanol plant, which was acquired in the fourth quarter 2009. The 2010 quarter also benefited from higher crude oil throughput due to more consistent operations during the period at the Company’s U.S. refineries. United States marketing operations generated a profit of $54.2 million in the 2010 quarter, up from $44.7 million of income in the 2009 quarter. The improvement in 2010 was essentially due to better merchandising and fuel margins in the current quarter compared to the 2009 quarter. The operating loss in the United Kingdom was $13.8 million in the third quarter of 2010 compared to a loss of $9.1 million in the same period a year ago. Operating margins at the Milford Haven, Wales, refinery were generally weaker in the 2010 quarter than in 2009. Worldwide refinery inputs were 267,988 barrels per day in the third quarter of 2010 compared to 250,081 in the 2009 quarter as all three refineries had improved throughputs compared to the prior year’s quarter. Worldwide petroleum product sales averaged 584,306 barrels per day in quarter three 2010, compared to 553,698 barrels per day in the same period in 2009. The 2010 sales volume increase was attributable to higher sales volumes in both the Company’s U.S. and U.K. marketing operations.
Refining and marketing operations in the first nine months of 2010 generated a profit of $104.7 million compared to a profit of $75.8 million in the 2009 period. In the United States, manufacturing operations lost $3.6 million in the 2010 period, significantly below the 2009 profit of $24.2 million due to both after-tax gains of $16.4 million on insurance settlements at the Meraux refinery in the prior-year period and weaker refining margins in 2010. The United States marketing business generated earnings of $132.7 million in the nine-month period of 2010, compared to earnings of $58.1 million in 2009 as retail margins were $0.04 per gallon stronger during the 2010 period compared to the prior year. Results in the United Kingdom reflected a loss of $24.4 million in the first nine months of 2010 compared to a loss of $6.5 million in the 2009 period. The reduction was primarily due to weaker refining margins on sale of petroleum products in 2010 compared to 2009 and lower production of finished products due to an approximate two-month shutdown for turnaround of the Milford Haven, Wales, refinery during 2010.
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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
Fuel and loss
Petroleum products sold – barrels per day
Total United States
United States Manufacturing
Asphalt, LPG and other
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 $34.5 million in the 2010 third quarter compared to net costs of $32.4 million in the third quarter of 2009. The 2010 results of corporate activities were unfavorable to 2009 primarily due to higher administrative costs, mostly associated with staff compensation expense. Net after-tax losses on transactions denominated in foreign currencies in the current quarter were $15.8 million compared to net losses of $17.0 million in the comparable 2009 period.
For the first nine months of 2010, corporate activities reflected net costs of $133.5 million compared to net costs of $7.5 million a year ago. Nine-month corporate costs in 2010 were significantly unfavorable to 2009 primarily related to the effects of transactions denominated in foreign currencies, and higher expenses for interest and administration. Total after-tax losses for foreign currency transactions were $58.8 million in the 2010 period compared to net benefits of $42.7 million in the first nine months of 2009. Net interest expense was unfavorable in 2010 compared to 2009 due to higher average levels of borrowed funds and lower levels of interest capitalized to oil and gas development projects. Administrative expense was also higher in 2010 mostly associated with increased employee compensation costs.
Financial Condition
Net cash provided by operating activities was $2.20 billion for the first nine months of 2010 compared to $1.19 billion during the same period in 2009. Changes in operating working capital other than cash and cash equivalents provided cash of $417.2 million in the first nine months of 2010, but used cash of $139.0 million in the first nine months of 2009. Cash generated from working capital changes in the 2010 period included a $244.4 million recovery of U.S. federal royalties paid in prior years on oil and natural gas production in the Gulf of Mexico. Cash of $2.01 billion in the 2010 period and $1.38 billion in 2009 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 $148.4 million in 2010 and $143.0 million in 2009, and for property additions and dry holes, which including amounts expensed, were $1.61 billion and $1.54 billion in the nine-month periods ended September 30, 2010 and 2009, respectively. Also, the purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $1.86 billion in the 2010 period and $1.76 billion in the 2009 period. Effective with the third quarter 2010, the Company’s annualized dividend rate was raised from $1.00 to $1.10 per share.
Total accrual basis capital expenditures for continuing operations were as follows:
Capital Expenditures – Continuing operations
Corporate and other
Total capital expenditures – continuing operations
A reconciliation of property additions and dry hole costs in the consolidated statements of cash flows to total capital expenditures follows.
Property additions and dry hole costs per cash flow statements
Geophysical and other exploration expenses
Capital expenditure accrual changes
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Financial Condition (Contd.)
Working capital (total current assets less total current liabilities) at September 30, 2010 was $705.2 million, a decrease of $488.9 million from December 31, 2009. 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 $612.1 million below fair value at September 30, 2010.
At September 30, 2010, long-term notes payable of $1,024.3 million had decreased in total by $328.8 million compared to December 31, 2009. A summary of capital employed at September 30, 2010 and December 31, 2009 follows.
Capital employed
Total capital employed
The Company’s ratio of earnings to fixed charges was 18.3 to 1 for the nine-month period ended September 30, 2010.
Accounting and Other Matters
Outlook
Average West Texas Intermediate crude oil prices in October 2010 averaged over $80 per barrel, which was about $5 per barrel above the third quarter 2010 average price. The Company expects its oil and natural gas production to average about 198,000 barrels of oil equivalent per day in the fourth quarter 2010. U.S. retail marketing margins have fallen in October versus the average margins achieved in the third quarter 2010. Additionally, margins remained under pressure during October at the Company’s refineries. The Company currently anticipates total capital expenditures for the full year 2010 to be approximately $2.6 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, political and regulatory instability, and uncontrollable natural hazards. For further discussion of risk factors, see Murphy’s 2009 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 J to this Form 10-Q report, Murphy periodically uses derivative commodity and financial instruments to manage risks associated with existing or anticipated transactions. There were short-term commodity derivative contracts in place at September 30, 2010 to hedge the value of about 0.9 million barrels of crude oil and 0.4 million barrels of intermediate products at the Company’s refineries. Additionally, on this date the Company had open fixed-price corn purchase commitments of approximately 5.3 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 an equivalent amount 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 $10.2 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 September 30, 2010 to hedge the value of the 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 $25.1 million, while a 10% weakening of the U.S. dollar would have increased the recorded net asset by approximately $34.3 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 September 30, 2010 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’s operations in the oil and gas business naturally lead to various risks and uncertainties. These risk factors are discussed in Item 1A. Risk Factors in our 2009 Form 10-K filed on February 26, 2010.
In April 2010, a drilling accident and subsequent oil spill occurred in the Gulf of Mexico at a property owned by other companies. The U.S. government declared a moratorium on drilling in the Gulf of Mexico after this accident. The moratorium forced the Company to defer planned exploration drilling in the Gulf of Mexico. In October 2010, the U.S. government lifted the moratorium on drilling in the Gulf of Mexico. However, it is unclear how new government regulations will impact the issuance of permits to drill in the Gulf. New government regulations covering offshore drilling operations may lead to higher costs for future drilling operations and delays for approval of drilling permits. Additionally, the Company could face higher costs for offshore insurance. The Company is unable to predict when it will be able to resume drilling operations in the Gulf of Mexico and how new regulations and any associated higher costs will ultimately impact its U.S. and worldwide operations.
The existing 45-cent per gallon federal excise tax credit earned on ethanol blended with gasoline in the U.S. is scheduled to expire at December 31, 2010. The U.S. government is considering whether to extend this or similar credits in 2011 and beyond. The elimination or significant reduction of the ethanol credit could have a detrimental effect on the Company’s U.S. fuel business. The Company cannot predict at this time how ethanol credits will be altered beginning in 2011, and whether any such change will materially affect its operations in future periods.
ITEM 6. EXHIBITS
The Exhibit Index on page 33 of this Form 10-Q report lists the exhibits that are hereby filed, incorporated by reference, or furnished with this report.
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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)
/s/ JOHN W. ECKART
John W. Eckart, Vice President and Controller (Chief Accounting Officer and Duly Authorized Officer)
November 5, 2010
(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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