UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
For the quarterly period ended September 30, 2009
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. þ 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). þ 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 þ No
Number of shares of Common Stock, $1.00 par value, outstanding at September 30, 2009 was 190,932,460.
TABLE OF CONTENTS
Part I – Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets
Consolidated Statements of Income
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 and Reports on Form 8-K
Signature
1
PART I – FINANCIAL INFORMATION
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
ASSETS
Current assets
Cash and cash equivalents
Canadian government securities with maturities greater than90 days at the date of acquisition
Accounts receivable, less allowance for doubtful accounts of $7,657 in 2009 and $7,303 in 2008
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 $4,391,138 in 2009 and $3,824,393 in 2008
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
Notes payable
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 191,626,348 in 2009 and 191,248,941 shares in 2008
Capital in excess of par value
Retained earnings
Accumulated other comprehensive income (loss)
Treasury stock, 693,888 shares of Common Stock in 2009 and 535,135 shares in 2008, at cost
Total stockholders’ equity
Total liabilities and stockholders’ equity
See Notes to Consolidated Financial Statements, page 7.
The Exhibit Index is on page 33.
2
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 (loss) from discontinued operations, net of income taxes
NET INCOME
INCOME PER COMMON SHARE – BASIC
Income (loss) from discontinued operations
Net income—Basic
INCOME PER COMMON SHARE – DILUTED
Net income—Diluted
Average common shares outstanding – basic
Average common shares outstanding – diluted
3
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)
Net income
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation
Retirement and postretirement benefit plan gains
COMPREHENSIVE INCOME
4
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
OPERATING ACTIVITIES
Income from discontinued operations
Adjustments to reconcile income from continuing operations 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 provided (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 securities2
Proceeds from maturity of investment securities2
Expenditures for major repairs
Other – net
Investing activities of discontinued operations
Sales proceeds
Other
Net cash required by investing activities
FINANCING ACTIVITIES
Increase (decrease) in notes payable
Decrease in 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
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
SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid
Interest paid more than (less than) amounts capitalized
Reclassified to conform to current presentation.
Represents cash invested in Canadian government securities with maturities greater than 90 days at the date of acquisition.
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 191,626,348 shares at September 30, 2009 and 191,022,032 shares at September 30, 2008
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
Accumulated Other Comprehensive Income (Loss)
Foreign currency translation gains (losses), net of income taxes
Retirement and postretirement benefit plan gains, net of income taxes
Treasury Stock
Cancellation of performance-based restricted stock and forfeitures
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, 2008. 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, 2009, and the results of operations, cash flows and changes in stockholders’ equity for the three-month and nine-month periods ended September 30, 2009 and 2008, 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 2008 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, 2009 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. The acquirer also assumed certain tax and other liabilities associated with the Ecuador properties sold. The Ecuador properties sold included 20% interests in producing Block 16 and the nearby Tivacuno area. The Company recorded a gain of $103.6 million, net of income taxes of $14.0 million, from the sale of the Ecuador properties in 2009. The Company used the proceeds of the sale to pay down debt and to partially fund ongoing development projects in other areas. At the time of the sale, the Ecuador properties produced approximately 6,700 net barrels per day of heavy oil and had net proved oil reserves of approximately 4.6 million barrels. Ecuador operating results prior to the sale, and the resulting gain on disposal, have been reported as discontinued operations. The consolidated financial statements for 2008 have been reclassified to conform to this presentation. In past reports, the operating results for the Ecuador properties were primarily included in the Ecuador segment in the Oil and Gas Operating Results table; interest expense associated with the business was previously included in Corporate results. 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 from the sold properties including the gain on sale.
Revenues, including a pretax gain on sale of $117,557 in 2009
Income before income tax expense
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C – Property, Plant and Equipment
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, 2009, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $365.2 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2009 and 2008.
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 $252.1 million of exploratory well costs capitalized more than one year at September 30, 2009, $177.7 million is in Malaysia, $59.0 million is in the U.S., $9.6 million is in the U.K., and $5.8 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 the U.K. further studies to evaluate the discovery are ongoing, and in Canada a continuing drilling and development program is in process.
In May 2008, the Company sold its interest in the Lloydminster area properties in Western Canada for a pretax gain of $91.3 million ($67.9 million after-tax). In January 2008, the Company sold its interest in Berkana Energy Corporation and recorded a pretax gain of $42.3 million ($40.4 million after-tax).
Note D – Financing Arrangements
In September 2009, the Company filed a Form S-3 registration statement with the U.S. Securities and Exchange Commission which permits the offer and sale of debt and/or equity securities. The Company may use this shelf registration, if needed, in future years to raise debt or equity capital to fund operational requirements. The shelf registration expires in September 2012.
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Note E – 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.
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 following tables provide the components of net periodic benefit expense for the three-month and nine-month periods ended September 30, 2009 and 2008.
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
Special termination benefits expense
Curtailment expense
The increase in net periodic benefit expense in 2009 compared to 2008 is primarily due to the decline in value of pension plan assets during 2008. Special termination benefits and curtailment expenses in the nine-month period ended September 30, 2009 related to an early retirement program for certain employees.
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Note F – Employee and Retiree Benefit Plans (Contd.)
Murphy previously disclosed in its financial statements for the year ended December 31, 2008 that it expected to contribute $50.2 million to its defined benefit pension plans and $4.9 million to its other postretirement benefits plan during 2009. The anticipated defined benefit pension plan contributions included $30.0 million of voluntary contributions in the U.S. During the nine-month period ended September 30, 2009, the Company made contributions of $51.4 million (including $30.0 million of voluntary contributions to the U.S. defined benefit pension plans) and remaining funding in 2009 for the Company’s domestic and foreign defined benefit pension and postretirement plans is anticipated to be $3.7 million.
Note G – Incentive Plans
The cost of all share-based payment transactions must be 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 June 30, 2017. The Company also has a Stock Plan for Non-Employee Directors (Directors’ Plan) that permits the issuance of restricted stock and stock options or a combination thereof to the Company’s Directors.
In February 2009, the Committee granted stock options for 1,057,000 shares at an exercise price of $43.95 per share. The Black-Scholes valuation for these awards was $15.15 per option. The Committee also granted 375,050 performance-based restricted stock units in February 2009. The fair value of the performance-based restricted stock units, using a Monte Carlo valuation model, was $42.42 per unit. Also in February 2009 the Committee granted 47,790 shares of time-lapse restricted stock to the Company’s Directors under the Directors’ 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 $44.65 per share.
Cash received from options exercised under all share-based payment arrangements for the nine-month periods ended September 30, 2009 and 2008 was $8.6 million and $21.5 million, respectively. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $3.5 million and $20.5 million for the nine-month periods ended September 30, 2009 and 2008, 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
10
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, 2009 and 2008. 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 2009 and 2008 periods but were not included in the computation of diluted EPS because the incremental shares from assumed conversion were antidilutive. These included 1,872,625 shares at a weighted average share price of $56.74 in each 2009 period and 929,071 shares at a weighted average share price of $72.745 in each 2008 period.
Note I – Financial Instruments and Risk Management
Murphy periodically utilizes derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest 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.
Crude Oil Purchase Price Risks – The Company purchases crude oil as feedstock at its U.S. and U.K. refineries and is therefore subject to commodity price risk. Short-term derivative instruments were outstanding at both September 30, 2009 and 2008 to manage the cost of about 0.6 million barrels and 0.9 million barrels, respectively, of crude oil at the Company’s refineries. The impact on consolidated income from continuing operations before income taxes from marking these derivative contracts to market as of the balance sheet dates was a benefit of $0.4 million and a charge of $15.9 million, respectively, in the nine-month periods ended September 30, 2009 and 2008.
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, 2009 to manage the risk of approximately $22 million of U.S. dollar balances associated with the Company’s Canadian operation and to manage the risk of approximately $100 million equivalent of ringgit balances in the Company’s Malaysian operations. The impact on consolidated income from continuing operations before taxes from marking these derivative contracts to market as of September 30, 2009 was a gain of $0.5 million in the nine-month period ended September 30, 2009.
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Note I – Financial Instruments and Risk Management(Contd.)
At September 30, 2009, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.
September 30, 2009
Asset Derivatives
Liability Derivatives
Balance SheetLocation
Commodity derivative contracts
Foreign exchange derivative contracts
For the nine-month period ended September 30, 2009, the gains and losses recognized in the consolidated statement of income for derivative instruments not designated as hedging instruments are presented in the following table.
Nine Months Ended September 30, 2009
Location of Gain (Loss)
Recognized in
Income on Derivative
The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheet. The fair value measurements for these assets and liabilities at September 30, 2009 are presented in the following table.
Assets
Derivative assets
Liabilities
Derivative liabilities
Nonqualified employee savings plan
Note J – Accumulated Other Comprehensive Income (Loss)
The components of Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheets at September 30, 2009 and December 31, 2008 are presented in the following table.
Foreign currency translation gains, net of tax
Retirement and postretirement benefit plan losses, net of tax
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Note K – Operating Leases
In 2009, wholly owned-subsidiaries of the Company assumed obligations for operating leases of a Floating, Drilling, Production, Storage and Offloading (FDPSO) vessel in the Republic of the Congo and a production platform in the Gulf of Mexico. The leases are for minimum periods of five to seven years. Required payments over the minimum lease periods for the Company’s working interest amount to $254.7 million. During the next five years these minimum payments are: fourth quarter 2009—$11.1 million; 2010—$44.3 million; 2011—$44.3 million; 2012—$44.4 million; 2013—$44.3 million; 2014—$34.8 million; and thereafter $31.5 million. During the construction period for these leased assets, the Company was considered the proportionate owner of this equipment for accounting purposes. With the acceptance of the equipment, the assets and liabilities associated with the leased equipment of approximately $282.7 million were removed from the Company’s balance sheet through a non-cash related sale and leaseback transaction. There was no impact on net income, cash flow or stockholders’ equity from these transactions.
Note L – Commitments and Contingencies
In September 2009, the Company entered into a forward sales contract to mitigate the price risk for a portion of the natural gas sales volumes in 2010 related to its Tupper field in Western Canada. The contract calls for natural gas deliveries of approximately 33 million cubic feet per day during 2010 and is priced at Cdn$5.30 per thousand cubic feet at the AECO “c” sales point. The contract will be accounted for as a normal sale for accounting purposes.
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
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Note L – Environmental and Other Commitments and Contingencies(Contd.)
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 two Superfund sites. The potential total cost to all parties to perform necessary remedial work at these sites may be substantial. However, based on current negotiations and available information, the Company believes that it is a de minimis party as to ultimate responsibility at these Superfund sites. 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 two sites or other Superfund sites. The Company believes that its share of the ultimate costs to clean-up the Superfund sites 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.
Based on the results of litigation entitled Kerr-McGee v. Allred, the Company has an unrecorded contingent gain for recovery of Gulf of Mexico federal royalties totaling approximately $244 million, plus accrued interest. In October 2009, the U.S. Supreme Court refused to review the decision handed down by the U.S. Court of Appeals for the Fifth Circuit whereby Kerr-McGee was held not liable for royalties when oil and/or natural gas price thresholds were exceeded for certain deepwater Gulf of Mexico leases. The Company paid federal royalties on similar leases when the prices exceeded the benchmark levels. The Company filed a claim in October 2009 requesting refund of these royalties plus interest with the U.S. Department of Interior, and awaits word on the outcome of the claim. The Company will recognize this benefit to income, net of applicable income tax effects, when the U.S. Department of Interior provides appropriate evidence that it intends to honor the Company’s request for refund. The Company cannot predict how or when the government will respond to this request for refund.
Class action litigation and related opt-out claims involving the Hurricane Katrina related crude oil release in 2005 at the Company’s Meraux, Louisiana refinery have been resolved. Remaining litigation arising out of this incident consists of fewer than ten individual claims from outside the class area for which the Company’s exposure is de minimis. The Company originally recorded expense of $18 million in 2006 related to settlement costs not expected to be covered by insurance. As a result of a confidential arbitral tribunal ruling issued on September 10, 2009 relating to liability insurance coverage issues, the Company recorded a benefit of $4.5 million in the third quarter 2009 to reduce the total overall expected expense related to this matter. Accordingly, the matter will not have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
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 expected before year end. 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.
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. Heretofore, the Company’s ownership interest has been 12.0%. The matter will be the subject of arbitration before final interests are established. This redetermination is expected to be finalized in 2010, and is retroactive to approximately January 2005. Upon completion of the redetermination process, a cash settlement is required among partners to balance cash flows retroactive to the effective date. Information filed with the arbiter indicates that the Company’s interest at Terra Nova will be reduced. During the nine-month period ended September 30, 2009, the Company recorded a $36.4 million pretax charge ($25.6 million after tax) to reflect the estimated liability that will be owed through September 2009 activity for the anticipated reduction in working interest to 11.5%. The final results of the arbitration process could further reduce the Company’s working interest. The
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Company cannot predict at this time how its final ownership interest will be affected by the redetermination process, and it is unable to determine whether the ultimate settlement of this matter will have a material adverse effect on its net income 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, 2009, the Company had contingent liabilities of $7.8 million under a financial guarantee and $166.0 million on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to the financial guarantee and letters of credit because it is believed that the likelihood of having these drawn is remote.
Note M – Accounting Matters
The Company adopted new accounting guidance issued by the Financial Accounting Standards Board (FASB) for noncontrolling interests in consolidated financial statements effective January 1, 2009. This guidance is to be applied prospectively, except for presentation and disclosure requirements which are applied retrospectively. This guidance required noncontrolling interests to be reclassified as equity, and consolidated net income and comprehensive income shall include the respective results attributable to noncontrolling interests. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.
The Company adopted new accounting guidance covering business combinations effective January 1, 2009. The new guidance established principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquired business. It also established how to recognize and measure goodwill acquired in the business combination or a gain from a bargain purchase, if applicable. This guidance impacts the recognition and measurement of assets and liabilities in business combinations that occur beginning in 2009. Assets and liabilities that arose from business combinations that occurred prior to 2009 are not affected by this guidance. The adoption of this guidance had no effect on the Company’s financial statements for the nine-month period ended September 30, 2009. The Company is unable to predict how the application of this guidance will affect its financial statements in future periods.
The Company adopted new accounting guidance which addresses disclosures about derivative instruments and hedging activities in January 2009. This guidance expands required disclosures regarding derivative instruments to include qualitative information about objectives and strategies for using derivatives, quantities disclosures about fair value amounts and gains and losses on derivative instruments, and disclosures about credit-risk related contingent features in derivative agreements. See Note I for further disclosures.
In 2009, the Company adopted new accounting guidance for determining whether instruments granted in share-based payment transactions are participating securities. This guidance specifies that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings per share (EPS) calculation under the two-class method, and also requires that all prior-period EPS calculations be adjusted retrospectively. The adoption of this guidance did not have a significant impact on the Company’s prior-period EPS calculations.
The Company adopted new accounting guidance addressing certain equity method investment accounting considerations in January 2009, which has been applied prospectively. The guidance addresses how to initially measure contingent consideration for an equity method investment, how to recognize other-than-temporary impairments of an equity method investment, and how an equity method investor is to account for a share issuance by an investee. The adoption of this guidance did not have a significant impact on the Company’s consolidated financial statements.
The Company adopted new accounting guidance addressing subsequent events effective June 30, 2009. The guidance clarified the accounting for and disclosure of subsequent events that occur after the balance sheet date through the date of issuance of the applicable financial statements. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements. See Note O for further disclosures.
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Note M – Accounting Matters (Contd.)
The FASB has issued its Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles. This guidance became effective for interim and annual periods ended after September 15, 2009 (the third calendar quarter for Murphy Oil) and recognized the FASB Accounting Standards Codification as the single source of authoritative nongovernment U.S. generally accepted accounting principles. The codification superseded all existing accounting standards documents issued by the FASB, and established that all other accounting literature not included in the codification is considered nonauthoritative. Although the codification does not change U.S. generally accepted accounting principles, it does reorganize the principles into accounting topics using a consistent structure. The codification also includes relevant U.S. Securities and Exchange Commission guidance following the same topical structure. Beginning with this Form 10-Q, all references to U.S. generally accepted accounting principles will use the new topical guidelines established with the codification. Otherwise, this new standard is not expected to have a material impact on the Company’s consolidated financial statements in future periods.
The FASB has provided additional guidance regarding disclosures about postretirement benefit plan assets, including how asset investment allocation decisions are made, the fair value of each major category of plan assets, and how fair value is determined for each major asset category. This guidance will be effective for the Company as of December 31, 2009. Upon adoption, no comparative disclosures are required for earlier years presented. The Company does not expect the adoption of this guidance to have a material impact on its consolidated financial statements in future periods.
In June 2009, FASB issued new guidance regarding accounting for transfers of financial assets. 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 guidance is effective for the Company beginning on January 1, 2010. The Company is currently evaluating this guidance and is unable to predict at this time how it will impact its consolidated financial statements in future periods.
In June 2009, FASB issued new guidance 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. This guidance is effective for the Company beginning on January 1, 2010. The Company is currently evaluating this guidance and is unable to predict at this time how it will impact its consolidated financial statements in future periods.
In December 2008, the U.S. Securities and Exchange Commission adopted revisions to oil and natural gas reserves reporting requirements which are effective for the Company at year-end 2009. The primary changes to reserves reporting include:
A revised definition of proved reserves, including the use of unweighted average prices for a 12-month period to compute such reserves,
Expanding the definition of oil and gas producing activities to include non-traditional and unconventional resources, which includes the Company’s synthetic oil operations in Alberta,
Allowing companies to voluntarily disclose probable and possible reserves in SEC filings,
Amending required proved reserve disclosures to include separate amounts for synthetic oil and gas,
Expanding disclosures of proved undeveloped reserves, including discussion of such proved undeveloped reserves five years old or more, and
Disclosure of the qualifications of the chief technical person who oversees the Company’s overall reserve process.
The Company is currently evaluating these new rules and cannot predict how the new rules will affect its future reporting of oil and natural gas reserves.
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Note N – Business Segments
(Millions of dollars)
Exploration and production2
United States
Canada
United Kingdom
Malaysia
Total
Refining and marketing
North America
Total operating segments
Corporate
Revenue/income from continuing operations
Discontinued operations, net of tax
Additional details about results of oil and gas operations are presented in the tables on pages 23 and 24.
Note O – Subsequent Events
A wholly-owned subsidiary of the Company purchased an ethanol plant in Hankinson, North Dakota on October 1, 2009. The plant has a rated capacity to produce 110 million gallons of ethanol per annum. The majority of the $92 million purchase price was financed with an $82 million nonrecourse loan held by former owners. The loan currently bears interest at 5.0% per year and is repayable in five years.
The Company has evaluated subsequent events through the date of issuance of these consolidated financial statements (November 6, 2009). In certain cases, events that occur after the balance sheet date lead to recognition and/or disclosure in the consolidated financial statements.
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Results of Operations
Murphy’s net income in the third quarter of 2009 was $188.9 million, $0.98 per diluted share, compared to net income of $584.4 million, $3.04 per diluted share, in the third quarter of 2008. The 2008 results included a loss from discontinued operations of $0.6 million, with no effect on diluted earnings per share. The lower income in 2009 primarily related to weaker results for both the Company’s exploration and production and refining and marketing businesses.
For the first nine months of 2009, net income totaled $518.8 million, $2.70 per diluted share, compared to net income of $1.613 billion, $8.39 per diluted share, for the same period in 2008. Nine-month income in 2009 compared unfavorably to 2008 due to lower earnings for exploration and production and refining and marketing operations. The 2009 net income included income from discontinued operations of $97.8 million, $0.51 per diluted share, with the amount primarily being generated from a gain on sale of Ecuador assets that occurred in March 2009. Net income for the nine months in 2008 included income from discontinued operations of $0.9 million, with no effect per diluted share.
Murphy’s income from continuing operations by operating segment is presented below.
Exploration and production
In the 2009 third quarter, the Company’s exploration and production continuing operations earned $184.1 million compared to $530.5 million in the 2008 quarter. Income in the 2009 quarter was adversely affected by significantly lower crude oil and natural gas sales prices compared to the 2008 quarter. The Company’s average realized worldwide sales prices for oil fell more than $51.00 per barrel in 2009 compared to 2008, and average North American natural gas sales prices were lower by $8.50 per thousand cubic feet. Higher oil and natural gas sales volume and lower exploration expenses partially offset the impact of lower oil and gas sales prices. Exploration expenses were $37.9 million in the third quarter of 2009 compared to $83.4 million in the same period of 2008. The Company’s refining and marketing operations generated income of $37.2 million in the 2009 third quarter compared to income of $85.8 million in the same quarter of 2008. The third quarter 2009 was affected by weaker margins for U.K. refining operations and U.S. retail marketing operations compared to 2008. The after-tax costs of corporate functions were $32.4 million in the 2009 third quarter compared to costs of $31.3 million in the 2008 period with the cost increase primarily due to lower net interest earned on invested cash balances in 2009.
For the nine months of 2009, the Company’s exploration and production continuing operations earned $352.7 million compared to $1.53 billion in the 2008 period. Earnings from continuing operations in 2009 were impacted by significantly lower realized crude oil and natural gas sales prices, and no significant gains on sale of assets, whereas 2008 included higher sales prices and significant gains on asset sales in Canada. Continuing operations excludes the results of discontinued operations in Ecuador, which had income of $97.8 million in the 2009 period mostly associated with a gain on sale of these assets. The Company’s refining and marketing operations had earnings of $75.8 million in the first nine months of 2009, compared to earnings of $173.3 million in the same 2008 period. The 2009 period included lower earnings in the North American downstream business compared to a year ago, caused by significantly weaker retail marketing margins in the U.S. Earnings from downstream operations in the U.K. in 2009 were significantly lower than 2008 due to weak margins in refining operations in the current period. Corporate after-tax costs were $7.5 million in the 2009 nine-month period compared to costs of $95.8 million in the 2008 period. Foreign currency exchange gains in 2009 compared to exchange losses in 2008 primarily accounted for the lower net costs in 2009.
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Results of Operations (Contd.)
Exploration and Production
Results of exploration and production continuing operations are presented by geographic segment below.
Other International
Third quarter 2009 vs. 2008
United States exploration and production operations had earnings of $6.0 million in the third quarter of 2009 compared to $41.0 million in the 2008 quarter. U.S. earnings were significantly lower in the 2009 period predominantly due to much weaker oil and natural gas sales prices. Higher U.S. oil production volumes and natural gas sales volumes were primarily attributable to start-up of production at the Thunder Hawk field in the Gulf of Mexico in the 2009 quarter, plus the effects of fields shut-in for part of the 2008 quarter in the Gulf of Mexico due to hurricanes Gustav and Ike. Production and depreciation expenses in the U.S. were significantly higher in 2009 mostly due to increased oil and natural gas production volumes. U.S. exploration expenses in the 2009 quarter were $17.3 million less than the prior year primarily due to lower dry hole costs and lower geological and geophysical expenses, somewhat offset by higher undeveloped lease amortization expense. Selling and general expenses in the U.S. were lower in the 2009 third quarter than in 2008 due to a larger credit in the current period for recovery of partners’ share of operated overhead as permitted under joint operating agreements.
Operations in Canada earned $44.6 million in the third quarter 2009 compared to $166.8 million in the 2008 quarter. Canadian earnings declined in the 2009 quarter mostly due to lower oil and natural gas sales prices and lower oil sales volumes. Oil production and sales volumes decreased in the 2009 period compared to 2008 primarily due to lower amounts produced offshore Eastern Canada and in the heavy oil area of Western Canada. Natural gas sales volumes increased in 2009 due to higher gas volumes produced at the Tupper area in British Columbia, which came on production in December 2008. Depreciation expense was higher in 2009 due to more natural gas production in the just completed quarter. Exploration expense was $19.9 million less in the 2009 quarter due mostly to lower lease amortization expense attributable to the Tupper West natural gas area in British Columbia.
United Kingdom operations earned $2.1 million in the 2009 third quarter, down from $20.5 million in the 2008 quarter. The 2009 reduction was due to a combination of lower crude oil and natural gas sales volumes and lower oil and gas sales prices in the current quarter. Production and depreciation expenses were lower in the 2009 period in the U.K. primarily due to the reduced crude oil and natural gas sales volumes.
Operations in Malaysia reported earnings of $156.2 million in the 2009 third quarter compared to earnings of $308.3 million during the same period in 2008. The earnings decline in 2009 in Malaysia was primarily attributable to lower crude oil sales prices. Total crude oil sales volumes increased in the 2009 quarter compared to the prior year due to higher production levels at the Kikeh field, offshore Sabah. Natural gas sales volumes in 2009 were due to start-up of Kikeh gas production in December 2008 and start-up of gas production offshore Sarawak in September 2009. No natural gas was produced in Malaysia in the 2008 quarter. Production and depreciation expenses were higher in Malaysia in the current quarter due to higher oil and natural gas sales volumes. Malaysian exploration expense was $25.6 million lower in 2009 primarily due to unsuccessful exploration drilling in the third quarter of 2008. Selling and general expense in Malaysia was a credit in both quarterly periods due to overhead charges to production and development operations under joint operating agreements.
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Exploration and Production (Contd.)
Third quarter 2009 vs. 2008 (Contd.)
Other international operations reported a loss of $24.8 million in the third quarter of 2009 compared to a loss of $6.1 million in the 2008 period. The unfavorable variance was primarily related to unsuccessful exploratory drilling costs in the Republic of the Congo and higher other exploration expense in this segment in the 2009 quarter. The Azurite field in Block MPS, offshore the Republic of the Congo, commenced oil production in August 2009.
On a worldwide basis, the Company’s crude oil, condensate and natural gas liquids prices averaged $61.13 per barrel in the third quarter 2009 compared to $112.55 per barrel in the 2008 period. Average oil and gas liquids production from continuing operations was 131,637 barrels per day in the third quarter of 2009 compared to 111,751 barrels per day in the third quarter of 2008, with the 18% increase primarily attributable to higher production at the Kikeh field in Malaysia and start-up of the Thunder Hawk and Azurite fields in the just completed quarter. Crude oil production was higher in the U.S. in the 2009 quarter mostly due to Thunder Hawk start-up and partial downtime in the 2008 quarter for Gulf of Mexico fields caused by two hurricanes. Canadian heavy oil production was lower in the 2009 quarter compared to 2008 due to normal decline and inclement weather at the Seal area in Alberta. Canadian offshore crude oil production fell in 2009 due to volume decline and a higher royalty rate at the Hibernia field and more equipment downtime at the Terra Nova field. North American natural gas sales prices averaged $3.01 per thousand cubic feet (MCF) in the 2009 quarter compared to $11.51 per MCF in the same quarter of 2008. Worldwide natural gas sales volumes averaged 182 million cubic feet per day in the third quarter 2009, up from 46 million cubic feet per day in the 2008 quarter, primarily due to production from the Tupper area in Western Canada and the Kikeh field offshore Sabah Malaysia, both of which started up in December 2008. Additionally, certain Gulf of Mexico fields were shut-in for a portion of the third quarter 2008 due to two hurricanes during the period. Natural gas sales volumes decreased in the U.K. in 2009 primarily due to lower volumes sold from the Amethyst and Mungo/Monan offshore fields.
Nine months 2009 vs. 2008
U.S. E&P operations produced income of $2.6 million for the nine months ended September 30, 2009 compared to income of $159.5 million in the 2008 period. The 2009 period had lower oil and natural gas sales prices, but higher crude oil and natural gas sales volumes. Production expenses in the U.S. were higher in 2009 mostly due to higher overall production. U.S. depreciation expense was unfavorable in 2009 due to combined impacts of higher production levels and higher per-unit depletion rates compared to 2008. Exploration expenses in the 2009 period in the U.S. were $25.9 million lower than 2008 due to less dry hole and geological and geophysical expenses, but partially offset by higher undeveloped leasehold amortization expense. Income taxes in 2009 included benefits from favorable adjustment of taxes related to prior years.
Canadian operations earned $38.8 million in the 2008 period compared to $554.5 million a year ago. Lower sales prices for crude oil and natural gas in 2009, coupled with after-tax gains of $108.3 million on sales of properties in 2008, primarily led to the earnings reduction in 2009. Higher natural gas volumes were sold in 2009 due to Tupper start-up, but crude oil sales volumes were lower in the current period. Lower Canadian production expense in 2009 was mostly related to less energy costs at Syncrude. Higher depreciation expense in 2009 in Canada was attributable to more natural gas sales volumes after start-up of production at Tupper. Exploration expenses in Canada were $36.4 million lower in 2009 primarily due to less seismic costs and less undeveloped lease amortization at the Tupper West natural gas area development.
Income in the U.K. for the nine-month period in 2009 was $9.1 million compared to $67.0 million a year ago, with the decrease primarily due to lower oil and natural gas sales volumes and sales prices. Production and depreciation expenses were both lower in 2009 than 2008 primarily due to the reduced production levels.
Malaysia operations earned $400.9 million in the first nine months of 2009 compared to earnings of $776.4 million in the 2008 period. The earnings decline was primarily caused by lower crude oil sales prices. Production at the Kikeh field increased during 2009 as more wells came on stream in late 2008. Depreciation expense in Malaysia was higher in 2009 and primarily related to the increase in Kikeh field production. Malaysian exploration expense was $34.7 million lower in 2009 mostly due to less unsuccessful exploration drilling and geophysical costs during the current year. Selling and general expense in 2009 was favorable compared to 2008 due to higher levels of costs charged to production and development operations under joint operating agreements.
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Nine months 2009 vs. 2008 (Contd.)
Other international operations reported a loss of $98.7 million in the first nine months of 2009 compared to a loss of $23.2 million in the 2008 period. The larger loss in the 2009 period was primarily due to higher dry hole costs in Australia and higher geophysical expenses offshore Suriname in 2009.
For the first nine months of 2009, the Company’s sales price for crude oil, condensate and natural gas liquids averaged $52.59 per barrel compared to $105.36 per barrel in 2008. Crude oil, condensate and gas liquids production from continuing operations in the first nine months of 2009 averaged 127,911 barrels per day compared to 106,993 barrels per day a year ago. The 20% increase in crude oil volumes was mostly attributable to higher Kikeh field production, offshore Malaysia. Production in the heavy oil area of Western Canada was lower in 2009 mostly due to less production at the Seal properties. Crude oil production offshore Eastern Canada was lower in 2009 due to less volumes produced at both the Hibernia and Terra Nova fields. Lower oil production at the Schiehallion field offshore the U.K. was mostly caused by equipment issues and maintenance downtime. The average sales price for North American natural gas in the first nine months of 2009 was $3.50 per MCF, down from $10.27 per MCF in 2008. Natural gas sales volumes in 2009 were 147 million cubic feet per day compared to 57 million cubic feet per day in 2008, with the greater than 150% increase due mostly to new production at the Tupper area in Western Canada and the Kikeh field, offshore Sabah, Malaysia.
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Selected operating statistics for the three-month and nine-month periods ended September 30, 2009 and 2008 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 – Kikeh
– other
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) – heavy
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, 2009 AND 2008
Three Months Ended September 30, 2009
Oil and gas sales and other 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 expenses
Results of operations (excluding corporate overhead and interest)
Three Months Ended September 30, 2008
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OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2009 AND 2008
Income tax expenses (benefits)
Nine Months Ended September 30, 2008
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Refining and Marketing
Results of refining and marketing operations are presented below by geographic segment.
The Company’s refining and marketing operations generated income of $37.2 million in the 2009 third quarter compared to earnings of $85.8 million in the same quarter of 2008. North American operations had a profit of $46.3 million in the 2009 period compared to a profit of $91.3 million in 2008. U.S. retail marketing margins were significantly weaker in the 2009 quarter compared to 2008. Operations in the United Kingdom incurred a loss of $9.1 million in the third quarter of 2009 compared to a loss of $5.5 million in the same period a year ago. Both the 2009 and 2008 quarters were adversely affected by weak refining margins in the U.K. Worldwide petroleum product sales averaged 553,698 barrels per day in 2009, compared to 535,284 barrels per day in the same period in 2008. Worldwide refinery inputs were 250,081 barrels per day in the third quarter of 2009 compared to 232,020 in the 2008 quarter. Refinery inputs in 2009 increased primarily due to a plant-wide turnaround at the Superior, Wisconsin refinery during the 2008 third quarter.
Refining and marketing operations in the first nine months of 2009 generated a profit of $75.8 million compared to a profit of $173.3 million in the 2008 period. In North America, the 2009 profit of $82.3 million was lower than the 2008 profit of $97.3 million as current-year results were unfavorable due to much weaker U.S. retail marketing margins in 2009 compared to 2008. Results in the United Kingdom reflected a loss of $6.5 million in the first nine months of 2009 compared to earnings of $76.0 million in the 2008 period as 2009 was adversely affected by significantly weaker refining margins on sales of petroleum products.
Refinery inputs – barrels per day
Petroleum products sold – barrels per day
Gasoline
Kerosine
Diesel and home heating oils
Residuals
Asphalt, LPG and other
LPG and other
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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 $32.4 million in the 2009 third quarter compared to net costs of $31.3 million in the third quarter of 2008. Net costs increased in 2009 compared to 2008 due to lower interest income earned on invested cash balances in 2009, but this was partially offset by lower net interest expense, which was mostly associated with lower interest rates charged on certain outstanding long-term debt, smaller losses on foreign currency exchange movements, and income tax benefits. The Company capitalized less interest expense in the 2009 quarter due to start-up of production in the third quarter 2009 at new fields in the Gulf of Mexico, the Republic of the Congo and Sarawak, Malaysia. The after-tax costs of foreign exchange were $17.0 million in the 2009 third quarter compared to costs of $17.5 million in 2008.
For the first nine months of 2009, corporate activities reflected net costs of $7.5 million compared to net costs of $95.8 million a year ago. The reduction in nine-month 2009 costs related primarily to more favorable foreign currency exchange effects and lower net interest expense, due to a combination of lower interest rates charged on certain outstanding debt and higher interest capitalized to development projects. Total after-tax costs for foreign currency exchange movements were a benefit of $42.7 million in the 2009 nine-month period compared to a cost of $27.9 million in the same 2008 period.
Financial Condition and Liquidity
At September 30, 2009, the Company’s total Cash and Cash Equivalents was $315.1 million, and Canadian Government Securities with Maturities Greater than 90 Days at the Date of Acquisition totaled another $794.3 million. The Company has a committed revolving loan facility with various U.S. and foreign banks totaling $1.962 billion, of which $1.08 billion was unused at September 30, 2009. The capacity of the committed loan facility will be reduced to $1.905 billion between June 2010 and June 2011 and then further reduced to $1.828 billion from June 2011 to maturity in June 2012. The Company also has unused uncommitted loan facilities totaling approximately $350 million. There is no guarantee that the Company could access borrowings under these uncommitted loan facilities. During the third quarter 2009 the Company filed a shelf registration with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through September 2012. The Company believes that with its present cash, invested cash and loan facilities there are adequate sources of financing to meet its anticipated needs.
Net cash provided by operating activities was $1.19 billion for the first nine months of 2009 compared to $2.60 billion during the same period in 2008. Changes in operating working capital other than cash and cash equivalents used cash of $139.0 million in the first nine months of 2009, but provided cash of $115.4 million in the 2008 period.
Other predominant uses of cash in both years were for dividends, which totaled $143.0 million in 2009 and $118.8 million in 2008, and for property additions and dry holes, which including amounts expensed, were $1.54 billion and $1.55 billion in the nine-month periods ended September 30, 2009 and 2008, respectively. Total capital expenditures were as follows:
Capital Expenditures – Continuing operations
Corporate and other
Total capital expenditures – continuing operations
Working capital (total current assets less total current liabilities) at September 30, 2009 was $1.20 billion, up $237.9 million from December 31, 2008. 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 $501.1 million below fair value at September 30, 2009.
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Financial Condition and Liquidity (Contd.)
At September 30, 2009, long-term notes payable of $1.48 billion had increased by $453.7 million compared to December 31, 2008. A summary of capital employed at September 30, 2009 and December 31, 2008 follows.
Capital employed
Total capital employed
The Company’s ratio of earnings to fixed charges was 13.4 to 1 for the nine-month period ended September 30, 2009.
Accounting and Other Matters
The Company adopted new accounting guidance which addresses disclosures about derivative instruments and hedging activities in January 2009. This guidance expands required disclosures regarding derivative instruments to include qualitative information about objectives and strategies for using derivatives, quantities disclosures about fair value amounts and gains and losses on derivative instruments, and disclosures about credit-risk related contingent features in derivative agreements. See Note I of this Form 10-Q for further disclosures.
The Company adopted new accounting guidance addressing subsequent events effective June 30, 2009. The guidance clarified the accounting for and disclosure of subsequent events that occur after the balance sheet date through the date of issuance of the applicable financial statements. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements. See Note O of this Form 10-Q for further disclosures.
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Accounting and Other Matters (Contd.)
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Outlook
Worldwide crude oil and North American natural gas prices have strengthened in October 2009 compared to the average price during the third quarter of 2009. The Company expects its oil and natural gas production to average about 193,000 barrels of oil equivalent per day in the fourth quarter 2009. During October 2009, U.S. retail marketing margins had weakened considerably due to rising wholesale gasoline prices, and refining margins have remained weak due to low demand for refined products. The Company currently anticipates total capital expenditures for the full year 2009 to be approximately $2.1 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 2008 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.
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 September 30, 2009 to hedge the cost of about 0.6 million barrels of crude oil at the Company’s refineries. A 10% increase in the respective benchmark price of crude oil would have increased the recorded liability associated with these derivative contracts by approximately $3.8 million, while a 10% decrease would have reduced the recorded liability by a similar amount. Changes in the fair value of these derivative contracts generally offset the changes in the value for an equivalent volume of crude oil feedstocks.
There were short-term derivative foreign exchange contracts in place at September 30, 2009 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 $7.8 million, while a 10% weakening of the U.S. dollar would have increased the recorded net asset by approximately $11.6 million. Changes in the fair value of these derivative contracts generally offset the financial statement impact of an equivalent volume of foreign currency exposures associated with other assets and/or liabilities.
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, 2009 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
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 herein is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
The Company has not identified any additional risk factors not previously disclosed in its Form 10-K filed on February 27, 2009.
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31
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
November 6, 2009
(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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