UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
For the quarterly period ended September 30, 2008
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 is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange act.
Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes x No
Number of shares of Common Stock, $1.00 par value, outstanding at September 30, 2008 was 190,484,694.
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 than 90 days at the date of acquisition
Accounts receivable, less allowance for doubtful accounts of $7,379 in 2008 and $7,484 in 2007
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 $3,799,516 in 2008 and $3,516,338 in 2007
Goodwill
Deferred charges and other assets
Total assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt
Notes payable
Accounts payable and accrued liabilities
Income taxes payable
Total current liabilities
Nonrecourse debt of a subsidiary
Asset retirement obligations
Deferred credits and other liabilities
Minority interest
Stockholders’ equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued
Common Stock, par $1.00, authorized 450,000,000 shares, issued 191,022,032 shares in 2008 and 189,972,970 shares in 2007
Capital in excess of par value
Retained earnings
Accumulated other comprehensive income
Treasury stock, 537,338 shares of Common Stock in 2008 and 258,821 shares in 2007, at cost
Total stockholders’ equity
Total liabilities and stockholders’ equity
See Notes to Consolidated Financial Statements, page 7.
The Exhibit Index is on page 30.
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
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
Impairment of long-lived assets
Accretion of asset retirement obligations
Interest expense
Interest capitalized
Total costs and expenses
Income before income taxes
Income tax expense
NET INCOME
NET INCOME PER COMMON SHARE
BASIC
DILUTED
Average common shares outstanding – basic
Average common shares outstanding – diluted
See Notes to Consolidated Financial Statements on page 7.
3
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)
Net income
Other comprehensive income (loss), net of tax
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 gains from disposition of assets
Net (increase) decrease in noncash operating working capital
Other
Net cash provided by operating activities
INVESTING ACTIVITIES
Property additions and dry hole costs
Proceeds from sales of assets
Purchases of marketable securities
Expenditures for major repairs
Other – net
Net cash required by investing activities
FINANCING ACTIVITIES
Increase in notes payable
Reductions 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 (required by) provided by financing activities
Effect of exchange rate changes on cash and cash equivalents
Net increase 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, net of refunds
Interest paid in excess of interest capitalized
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 191,022,032 shares in 2008 and 189,522,070 shares in 2007
Balance at beginning of period
Exercise of stock options
Issuance of time-based restricted stock
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
Cumulative effect of changes in accounting principles
Net income for the period
Cash dividends
Accumulated Other Comprehensive Income
Cumulative effect of change in accounting principle
Foreign currency translation (losses) gains, net of income taxes
Retirement and postretirement benefit plan adjustments, net of income taxes
Treasury Stock
Cancellation and forfeitures of performance-based restricted stock
Total Stockholders’ Equity
See notes to consolidated financial statements on 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, 2007. 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, 2008, and the results of operations, cash flows and changes in stockholders’ equity for the three-month and nine-month periods ended September 30, 2008 and 2007, 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 2007 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, 2008 are not necessarily indicative of future results.
Note B – Property, Plant and Equipment
The FASB Staff Position (FSP) 19-1 applies to companies that use the successful efforts method of accounting and it clarifies that 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, 2008, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $306.0 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2008 and 2007.
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
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note B – Property, Plant and Equipment (Contd.)
Of the $261.5 million of exploratory well costs capitalized more than one year at September 30, 2008, $169.3 million is in Malaysia, $60.3 million is in the Republic of Congo, $26.8 million is in the U.S., and $5.1 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 Republic of Congo a development program is underway for the offshore Azurite field. In the U.S. drilling and development operations are planned, and in Canada a continuing drilling and development program is underway.
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 C – 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 now frozen 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, 2008 and 2007.
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
The increase in net periodic benefit expense in 2008 compared to 2007 is primarily due to the December 1, 2007 purchase of the remaining 70% interest in the Milford Haven, Wales refinery.
Beginning in 2008 the Company has reduced its expected annual return on U.S. retirement plan assets from 7.0% to 6.5%.
During the nine-month period ended September 30, 2008, the Company made contributions of $46.9 million to domestic and foreign retirement plans and $3.1 million to the postretirement benefit plan. Remaining funding in 2008 for the Company’s defined benefit pension plans and postretirement plan are anticipated to be $9.8 million and $1.6 million, respectively.
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Note D – Incentive Plans
SFAS No. 123R, Share Based Payment, requires that the cost resulting from all share-based payment transactions be recognized as an expense in the financial statements using a fair value-based measurement method over the periods that the awards vest. The Company adopted SFAS No. 123R on January 1, 2006. Prior to 2006, the Company used APB No. 25 to account for stock-based compensation.
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 Employee Stock Purchase Plan was amended to increase the number of shares authorized to be issued under the plan from 600,000 to 980,000, and to extend the term of the plan through June 30, 2017. The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock and stock options or a combination thereof to the Company’s Directors.
In February 2008, the Committee granted stock options for 932,500 shares at an exercise price of $72.745 per share. The Black-Scholes valuation for these awards was $17.69 per option. The Committee also granted 328,000 performance-based restricted stock units and 60,000 shares of time-lapse restricted stock units in February 2008 under the 2007 Long-Term Plan approved by shareholders on May 9, 2007. The fair value of the performance-based restricted stock units, using a Monte Carlo valuation model, was $59.445 per unit, while the time-lapse restricted stock units were valued at $71.78 per unit. Also in February the Committee granted 24,930 shares of time-lapse restricted stock to the Company’s Directors under the 2003 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 $71.78 per share.
Cash received from options exercised under all share-based payment arrangements for the nine-month periods ended September 30, 2008 and 2007 was $21.5 million and $33.8 million, respectively. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $20.5 million and $24.1 million for the nine-month periods ended September 30, 2008 and 2007, 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 E – 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, 2008 and 2007. The following table reconciles the weighted-average shares outstanding used for these computations.
(Weighted-average shares)
Basic method
Dilutive stock options
Diluted method
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Note E – Earnings per Share (Contd.)
Certain options to purchase shares of common stock were outstanding during the 2008 and 2007 periods but were not included in the computation of diluted EPS because the incremental shares from assumed conversion were antidilutive. These included 929,071 shares at a weighted average share price of $72.745 in each 2008 period and 1,545,650 shares at a weighted average share price of $53.70 in each 2007 period.
Note F – Financial Instruments and Risk Management
Murphy periodically utilizes derivative instruments to manage certain risks related to interest rates, 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 use derivatives with leveraged or complex features. Derivative instruments are traded primarily with 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 September 30, 2008 and 2007 to manage the cost of about 0.9 million barrels and 1.7 million barrels, respectively, of crude oil at the Company’s Meraux, Louisiana refinery. The impact on consolidated income before taxes from marking these derivative contracts to market as of the balance sheet date was a charge of $15.9 million and $7.1 million in the nine-month periods ended September 30, 2008 and 2007, respectively.
Foreign Currency Exchange Risks – The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. There were no short-term derivative instruments outstanding at September 30, 2008 to manage the risk of foreign currency exchange.
Note G – Accumulated Other Comprehensive Income
The components of Accumulated Other Comprehensive Income (AOCI) on the Consolidated Balance Sheets at September 30, 2008 and December 31, 2007 are presented in the following table.
Foreign currency translation gains, net of tax
Retirement and postretirement benefit plan adjustments, net of tax
Note H – 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; 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.
In addition to being subject to numerous laws and regulations intended to protect the environment and/or impose remedial obligations, the Company is also involved in personal injury and property damage claims, allegedly caused by exposure to or by the release or disposal of materials manufactured or used in the Company’s operations. The Company operates or has previously operated certain sites and facilities, including three refineries, five terminals, and approximately 125 service stations for which known or potential obligations for environmental remediation exist. In addition the Company operates or has operated numerous oil and gas fields that may require some form of remediation, which is generally provided for by the Company’s asset retirement obligation.
10
Note H – Environmental and Other Contingencies (Contd.)
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.
The U.S. Environmental Protection Agency (EPA) currently considers the Company a Potentially Responsible Party (PRP) at three Superfund sites. The potential total cost to all parties to perform necessary remedial work at these sites may be substantial. Based on currently 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 three sites or other Superfund sites. The Company believes that its share of the ultimate costs to clean-up the three 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.
On September 9, 2005, a class action lawsuit was filed in federal court in the Eastern District of Louisiana seeking unspecified damages to the class comprised of residents of St. Bernard Parish caused by a release of crude oil at Murphy Oil USA, Inc.’s (a wholly-owned subsidiary of Murphy Oil Corporation) Meraux, Louisiana, refinery as a result of flood damage to a crude oil storage tank following Hurricane Katrina. Additional class action lawsuits were consolidated with the first suit into a single action in the U.S. District Court for the Eastern District of Louisiana. In September 2006, the Company reached a settlement with class counsel and on October 10, 2006, the court granted preliminary approval of a class action Settlement Agreement. A Fairness Hearing was held January 4, 2007 and the court entered its ruling on January 30, 2007 approving the class settlement. The majority of the settlement of $330 million will be paid by insurance. The Company recorded an expense of $18 million in 2006 related to settlement costs not expected to be covered by insurance. As part of the settlement, all properties in the class area received a fair and equitable cash payment and have had residual oil cleaned. As part of the settlement, the Company offered to purchase all properties in an agreed area adjacent to the west side of the Meraux refinery; these property purchases and associated remediation have been paid by the Company at a cost of $55 million. As of September 30, 2008, the Company has fulfilled its obligations under the Class Action Settlement Agreement. Approximately 40 non-class action suits regarding the oil spill have been filed and remain pending. The Company believes that insurance coverage exists and it does not expect to incur significant costs associated with this litigation. On August 14, 2007, four of the Company’s high level excess insurers noticed the Company for arbitration in London. The insurers do not deny coverage, but seek arbitration as to whether and to what extent expenditures made by the Company in resolving the oil spill litigation have reached the attachment point for covered loss under their respective policies. The Company’s position is that full coverage should be afforded. Accordingly, the Company believes neither the ultimate resolution of the remaining litigation nor the insurance arbitration will have a material adverse effect on its net income, financial condition or liquidity in a future period.
On June 10, 2003, a fire severely damaged the Residual Oil Supercritical Extraction (ROSE) unit at the Company’s Meraux, Louisiana refinery. The ROSE unit recovers feedstock from the heavy fuel oil stream for conversion into gasoline and diesel. Subsequent to the fire, numerous class action lawsuits have been filed seeking damages for area residents. All the lawsuits have been administratively consolidated into a single legal action in St. Bernard Parish, Louisiana, except for one such action which was filed in federal court. Additionally, individual residents of Orleans Parish, Louisiana, have filed an action in that venue. On May 5, 2004, plaintiffs in the consolidated action in St. Bernard Parish amended their petition to include a direct action against certain of the Company’s liability insurers. The St. Bernard Parish action has since been removed to federal court, which issued an order on July 25, 2008 denying plaintiff’s request to certify the case as a class action. In responding to this direct action, one of the Company’s insurers, AEGIS, has raised lack of coverage as a defense. The Company believes that this contention lacks merit and has been advised by counsel that the applicable policy does provide coverage for the underlying incident. Because the Company believes that insurance coverage exists for this matter, it does not expect to incur any significant costs associated with the lawsuits. Accordingly, the Company continues to believe that the ultimate resolution of the June 2003 ROSE fire litigation will not have a material adverse effect on its net income, financial condition or liquidity in a future period.
11
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.
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, 2008, the Company had contingent liabilities of $8.5 million under a financial guarantee and $128.4 million on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to these letters of credit because it is believed that the likelihood of having these drawn is remote.
Note I – Accounting Matters
In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, Fair Value Measurements (SFAS No. 157). This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This statement applies under other accounting pronouncements that require or permit fair value measurements, and where applicable simplifies and codifies related guidance within GAAP and does not require any new fair value measurements. The statement was originally effective for fiscal years beginning January 1, 2008. On February 12, 2008, the FASB issued FSP No. 157-2 that delayed for one year the effective date of SFAS No. 157 for most nonfinancial assets and nonfinancial liabilities. Provisions of the statement are to be applied prospectively except in limited situations. The Company adopted this statement as of January 1, 2008 and the adoption had no material impact on its consolidated financial statements. See further disclosures at Note J.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS No. 159). This pronouncement permits companies with eligible financial assets and financial liabilities to measure these items at fair value in the financial statements. This option to measure at fair value is both instrument specific and irrevocable. If the fair value option is elected, certain additional disclosures are required and financial statements for periods prior to the adoption may not be restated. The Company adopted this standard as of January 1, 2008, but the Company chose not to elect fair value measurement for any financial assets and financial liabilities, and therefore, the adoption of SFAS No. 159, had no impact on the Company’s consolidated balance sheet or consolidated statement of income.
In June 2007, the FASB ratified the Emerging Issues Task Force’s Issue No. 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards (EITF No. 06-11). This new guidance was effective for the Company beginning in January 2008 and required that income tax benefits received by the Company for dividends paid on share-based incentive awards be recorded in Capital in Excess of Par Value in Stockholders’ Equity. Under certain circumstances, such tax benefits received on awards that do not vest could be reclassified to reduce income tax expense in the Consolidated Statements of Income. The effect of adopting EITF No. 06-11 was not material to the Company’s consolidated financial statements.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51. Upon adoption, this statement will require noncontrolling interests to be reclassified as equity, and consolidated net income and comprehensive income shall include the respective results attributable to noncontrolling interests. This statement is effective for the Company beginning January 1, 2009. It is to be applied prospectively and early adoption is not permitted. The Company does not expect this statement to have a significant effect on its consolidated financial statements.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations. This statement establishes 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 establishes how to recognize and measure goodwill acquired in the business combination or a gain from a bargain purchase, if applicable. This statement shall be applied prospectively by the Company to any
12
Note I – Accounting Matters (Contd.)
business combination that occurs on or after January 1, 2009. Early application is prohibited. Assets and liabilities that arise from business combinations occurring prior to 2009 shall not be adjusted upon application of this statement. This statement will impact the recognition and measurement of assets and liabilities in business combinations that occur after 2008, and the Company is unable to predict at this time how the application of this statement will affect its financial statements in future periods.
In March 2008, the FASB issued SFAS No. 161, Disclosure about Derivative Instruments and Hedging Activities. This statement is effective for the Company beginning in January 2009, and it 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. The Company does not expect this statement to have a significant effect on its consolidated financial statements.
In June 2008, the FASB issued FASB Staff Position on EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities (FSP EITF 03-6-1). This statement provides 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. All prior-period EPS calculations must be adjusted retrospectively. This statement is effective for the Company in 2009. Although the Company is in the process of evaluating this statement, it does not expect the effect of adopting this statement in 2009 to have a significant impact on its prior-period EPS calculations.
Note J – Assets and Liabilities Measured at Fair Value
As described in Note I, the Company adopted SFAS No. 157, Fair Value Measurements (SFAS No. 157), on January 1, 2008, other than for nonrecurring nonfinancial assets and liabilities, which will be effective for the Company on January 1, 2009. SFAS No. 157 establishes a fair value hierarchy 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 fair value measurements for the Company’s financial assets and liabilities accounted for at fair value on a recurring basis at September 30, 2008 are presented in the following table.
(thousands of dollars)
Total assets at fair value
Nonqualified employee savings plan
Commodity derivatives
Total liabilities at fair value
Market value for Canadian government securities approximates cost plus earned interest.
13
Note K – Business Segments
(Millions of dollars)
Exploration and production*
United States
Canada
United Kingdom
Malaysia
Ecuador
Total
Refining and marketing
North America
Total operating segments
Corporate
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Results of Operations
Murphy’s net income in the third quarter of 2008 was $584.4 million, $3.04 per diluted share, compared to net income of $199.5 million, $1.04 per diluted share, in the third quarter of 2007. The higher income in 2008 primarily related to improved earnings in both the Company’s exploration and production and refining and marketing businesses, partially offset by higher net costs for corporate activities.
For the first nine months of 2008, net income totaled $1.613 billion, $8.39 per diluted share, compared to net income of $560.4 million, $2.94 per diluted share, for the same period in 2007. The higher nine-month income in 2008 compared to 2007 was primarily attributable to higher earnings in the exploration and production business, partially offset by weaker earnings for refining and marketing operations and higher net corporate costs.
Murphy’s net income by operating segment is presented below.
Exploration and production
In the 2008 third quarter, the Company’s exploration and production operations earned $529.9 million compared to $150.8 million in the 2007 quarter. Income in the 2008 quarter was favorably affected by higher crude oil and natural gas sales prices and higher crude oil sales volumes. Exploration expenses were $83.4 million in the third quarter of 2008 compared to $42.5 million in the same period of 2007. The Company’s refining and marketing operations generated income of $85.8 million in the 2008 third quarter compared to income of $73.2 million in the same quarter of 2007. The third quarter 2008 benefited from much stronger U.S. retail marketing margins compared to 2007, but refining margins in the U.S. and U.K. were significantly weaker in the 2008 period. The after-tax costs of the corporate function were $31.3 million in the 2008 third quarter compared to $24.5 million in the 2007 period with the cost increase due to higher net interest costs and larger foreign exchange losses in 2008.
For the nine months of 2008, the Company’s exploration and production operations earned $1.535 billion compared to $388.9 million in the 2007 period. Earnings in 2008 benefited from significantly higher realized oil sales prices, higher oil sales volumes, and gains on sale of assets. The Company’s refining and marketing operations had earnings of $173.3 million in the first nine months of 2008, compared to earnings of $233.1 million in the same 2007 period. The 2008 period included lower earnings in the North American downstream business compared to a year ago, primarily caused by significantly weaker refining margins in 2008, but partially offset by stronger margins in U.S. retail marketing operations. Earnings from downstream operations in the U.K. improved in 2008 compared to 2007 due to better margins in refining operations and higher sales volumes due to the acquisition of the remaining 70% interest in the Milford Haven refinery in December 2007. Corporate after-tax costs were $95.8 million in the 2008 period compared to costs of $61.6 million in the 2007 period. Higher net interest expense, unfavorable foreign currency exchange results and higher administrative expenses accounted for the higher net costs in 2008.
15
Results of Operations (Contd.)
Exploration and Production
Results of exploration and production operations are presented by geographic segment below.
Other International
Third quarter 2008 vs. 2007
United States exploration and production operations reported quarterly earnings of $41.0 million in the third quarter of 2008 compared to earnings of $24.8 million in the 2007 quarter. U.S. earnings were higher in the 2008 period due mostly to higher oil and natural gas sales prices. Lower U.S. oil production volumes and lower natural gas sales volumes were mostly attributable to production shut-in in the Gulf of Mexico associated with Hurricanes Gustav and Ike. Depreciation expense in the U.S. was higher in 2008 primarily due to higher per-unit depletion rates. U.S. exploration expenses in the 2008 period increased $11.3 million from the prior year primarily due to higher dry hole costs and higher leasehold amortization, somewhat offset by lower geological and geophysical expenses. Selling and general expenses in the U.S. were lower in the 2008 period than in 2007 due to a real estate donation in the prior year.
Operations in Canada earned $166.8 million in the third quarter 2008 compared to $107.1 million in the 2007 quarter. Canadian earnings improved in the 2008 quarter mostly due to higher oil sales prices. Oil production and sales volumes declined in the 2008 period compared to 2007 primarily due to less oil produced offshore Eastern Canada and in the heavy oil area of Western Canada. Natural gas sales volumes declined in 2008 mostly due to sale of Berkana Energy in January 2008. Depreciation expense was lower in 2008 due to less oil and natural gas production and sales of properties. Exploration expense was $10.0 million higher in the 2008 period due to more lease amortization expense attributable to the Tupper natural gas area in British Columbia, but partially offset by lower dry hole and geophysical expenses. The 2007 quarter included $8.3 million in income tax benefits related to adjustments of estimated prior-period taxes.
United Kingdom operations earned $20.5 million in the 2008 quarter, up from $11.0 million in the 2007 quarter. The 2008 improvement was primarily due to higher crude oil and natural gas sales prices in the current quarter. In addition, the 2008 quarter included higher U.K. crude oil and natural gas sales volumes. Production and depreciation expenses were higher in the 2008 period in the U.K. primarily due to the increase in crude oil and natural gas sales volumes.
Operations in Malaysia reported earnings of $308.3 million in the 2008 quarter compared to earnings of $4.3 million during the same period in 2007. The earnings improvement in 2008 in Malaysia was primarily due to higher crude oil sales volumes caused by the continued ramp-up of production during 2008 at the Kikeh field. Kikeh came on production in the third quarter of 2007, but the first sale from this field occurred in the fourth quarter of 2007. Production and depreciation expenses were higher in Malaysia in the current period also due to higher sales volumes. Malaysian exploration expense was higher in 2008 due to an unsuccessful exploration well in Block K. Selling and general expense in Malaysia was lower in the 2008 period due to higher charges to production and development operations under the joint operating agreement at Kikeh.
Operations in Ecuador resulted in a net loss of $0.6 million in the third quarter of 2008 compared to a profit of $10.3 million in the 2007 period. The 2008 results were unfavorable primarily due to a combination of lower realized oil sales prices caused by higher revenue sharing taken by the Ecuadorian government in the 2008 quarter, lower crude oil sales volumes, and an unfavorable income tax adjustment in 2008 related to the prior year. Beginning in mid- October 2007, the government of Ecuador claimed 99% of crude oil sales prices that exceeded a benchmark price,
16
Exploration and Production (Contd.)
Third quarter 2008 vs. 2007 (Contd.)
which was approximately $24.31 per barrel in September 2008. Prior to this change, the government’s revenue sharing was 50% of realized prices that exceeded the benchmark price. Production expense in Ecuador was lower in 2008 due to less crude oil sales volumes. See page 25 for further discussion regarding Ecuador.
Other international operations reported a loss of $6.1 million in the third quarter of 2008 compared to a loss of $6.7 million in the 2007 period. The favorable variance was primarily related to slightly lower administrative costs in the 2008 quarter.
On a worldwide basis, the Company’s crude oil, condensate and natural gas liquids prices averaged $107.98 per barrel in the third quarter 2008 compared to $63.96 per barrel in the 2007 period. Average oil and gas liquids production was 118,797 barrels per day in the third quarter of 2008 compared to 87,962 barrels per day in the third quarter of 2007, with the increase primarily attributable to ramp-up of production at the Kikeh field in Malaysia during the 2008 period. Crude oil production was lower in the U.S. in 2008 mostly due to shut-in of Gulf of Mexico fields caused by two hurricanes during the third quarter. Certain offshore oil and natural gas production remained shut-in during October and early November 2008. There was no Canadian light oil production in the 2008 third quarter due to sale of the Company’s interest in Berkana Energy in January 2008. Canadian heavy oil production was lower in the 2008 quarter compared to 2007 due to sale of the Lloydminster area properties during the second quarter of 2008. Canadian offshore crude oil production fell in 2008 due to a production decline at the Hibernia field and more equipment downtime and a higher royalty rate at the Terra Nova field. Ecuador oil production was lower in 2008 due to less drilling activity in Block 16 following the increase in the government revenue share in October 2007. North American natural gas sales prices averaged $11.51 per thousand cubic feet (MCF) in the most recent quarter compared to $6.22 per MCF in the same quarter of 2007. Natural gas sales volumes averaged 46 million cubic feet per day in the third quarter 2008, down from 56 million cubic feet per day in the 2007 quarter, due to a combination of lower volumes in Canada caused by the sale of Berkana Energy in January 2008 and Gulf of Mexico fields shut-in during the third quarter of 2008 due to two hurricanes during the period. Natural gas sales volumes increased in the U.K. in 2008 primarily due to higher volumes sold from the Amethyst and Mungo/Monan offshore fields.
The sales prices for crude oil and natural gas have declined significantly in the fourth quarter 2008 compared to the average prices in the third quarter and for the first nine months of 2008.
Nine months 2008 vs. 2007
U.S. E&P operations produced income of $159.5 million for the nine months ended September 30, 2008 compared to income of $59.3 million in the 2007 period. The 2008 period had higher oil and natural gas sales prices and higher natural gas sales volumes, but lower crude oil sales volumes. Production expenses in the U.S. were lower in 2008 mostly due to less costs for workovers and other field maintenance. U.S. depreciation expense was unfavorable in 2008 due to higher per-unit depletion rates compared to 2007. Exploration expenses in the 2008 period in the U.S. were $2.0 million lower than 2007 due to less dry holes expense in 2008, but partially offset by higher geological and geophysical and leasehold amortization expenses in 2008.
Canadian operations earned $554.5 million in the 2008 period compared to $263.6 million a year ago. Higher sales prices for crude oil and natural gas and after-tax gains of $108.3 million on sales of properties primarily led to the increase in earnings. Higher Canadian production expenses in 2008 were mostly related to higher energy costs at Syncrude. Lower depreciation expense in 2008 in Canada was attributable to less oil and natural gas volumes produced and sold. Exploration expenses in Canada were $58.3 million higher in 2008 primarily due to more seismic costs and higher undeveloped lease amortization for new acreage acquired at the Tupper field in British Columbia, but these were partially offset by lower dry hole expense during 2008.
Income in the U.K. for the nine-month period in 2008 was $67.0 million compared to $37.9 million a year ago, with the increase primarily due to higher oil and natural gas sales prices and higher natural gas sales volumes, partially offset by lower crude oil sales volumes.
17
Nine months 2008 vs. 2007 (Contd.)
Malaysia operations earned $776.4 million in the first nine months of 2008 compared to earnings of $29.2 million in the 2007 period. The earnings improvement was primarily caused by crude oil sales volumes associated with the Kikeh field, offshore Sabah, which commenced production in the third quarter of 2007. Production at Kikeh increased during 2008 as more wells came on stream. Average crude oil sales prices were also significantly higher in 2008 than in 2007. Production and depreciation expenses in Malaysia were significantly higher and were related to the increase in Kikeh field production. Malaysian exploration expense was higher in 2008 mostly due to more costs for unsuccessful exploration drilling during 2008. Selling and general expense in Malaysia declined in 2008 due to higher levels of costs charged to production and development operations.
Earnings in Ecuador were $0.9 million for the first nine months of 2008 compared to $24.3 million for the 2007 period. The earnings decline in 2008 was due to higher revenue sharing with the government for sales prices above a benchmark price. In addition, crude oil production and associated sales volumes were lower in 2008 due to less spending on development drilling following the increase in government revenue sharing that took effect in October 2007. See page 25 for further discussion regarding Ecuador.
Other international operations reported a loss of $23.2 million in the first nine months of 2008 compared to a loss of $25.4 million in the 2007 period. The smaller loss in the 2008 period was primarily due to lower geophysical expenses in the Republic of Congo, but partially offset by higher costs in 2008 for exploration and administrative activities in other foreign jurisdictions.
For the first nine months of 2008, the Company’s sales price for crude oil, condensate and natural gas liquids averaged $100.53 per barrel compared to $56.10 per barrel in 2007. Crude oil, condensate and gas liquids production in the first nine months of 2008 averaged 114,559 barrels per day compared to 84,169 barrels per day a year ago. The increase was mostly attributable to Kikeh field production, offshore Malaysia, which continued to ramp up during 2008, but production volumes were lower in the Gulf of Mexico mostly caused by shut-in of fields due to third quarter hurricanes. Production in the heavy oil area of Western Canada was lower mostly due to the sale of the Lloydminster property in the second quarter 2008. Oil production was lower at the West Patricia field, offshore Sarawak, Malaysia, due to both field decline and a lower percentage of production allocable to the Company under the production sharing contract. The average sales price for North American natural gas in the first nine months of 2008 was $10.27 per MCF, up from $7.16 per MCF in 2007. Natural gas sales volumes in 2008 were 57 million cubic feet per day compared to 58 million cubic feet per day in 2007, with the decrease due mostly to wells shut-in by two hurricanes in the third quarter 2008. Lower natural gas volumes in Canada were caused by the sale of the Company’s interest in Berkana Energy in January 2008.
Additional details about results of oil and gas operations are presented in the tables on pages 20 and 21.
18
Selected operating statistics for the three-month and nine-month periods ended September 30, 2008 and 2007 follow.
Net crude oil, condensate and gas liquids produced – barrels per day
Canada – light
– heavy
– offshore
– synthetic
Net crude oil, condensate and gas liquids sold – barrels per day
Net natural gas sold – thousands of cubic feet per day
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)
Ecuador (5)
Natural gas – dollars per thousand cubic feet
United States (2)
Canada (3)
United Kingdom (3)
19
OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007
Three Months Ended September 30, 2008
Oil and gas sales and other revenues
Production expenses
Exploration expenses
Dry holes
Geological and geophysical
Undeveloped lease amortization
Total exploration expenses
Results of operations before taxes
Income tax expenses
Results of operations (excluding corporate overhead and interest)
Three Months Ended September 30, 2007
20
OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007
Nine Months Ended September 30, 2008
Nine Months Ended September 30, 2007
21
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 $85.8 million in the 2008 third quarter compared to earnings of $73.2 million in the same quarter of 2007. North American operations had a profit of $91.3 million in the 2008 period compared to $63.9 million in 2007. U.S. retail marketing margins improved significantly in the 2008 quarter compared to 2007. Refining margins in the U.S., however, were quite weak in the 2008 quarter, but were strong in the third quarter of 2007. Operations in the United Kingdom incurred a loss of $5.5 million in the third quarter of 2008 compared to earnings of $9.3 million in the same period a year ago. The 2008 quarter was adversely affected by weaker U.K. refinery margins. Worldwide petroleum product sales averaged 535,284 barrels per day in 2008, compared to 472,876 barrels per day in the same period in 2007. The 2008 sales volume increase was attributable to higher sales volumes in the U.K. associated with the Milford Haven refinery acquisition. Worldwide refinery inputs were 232,020 barrels per day in the third quarter of 2008 compared to 176,785 in the 2007 quarter. Refinery inputs in 2008 increased in the U.K. due to the Milford Haven acquisition, but were lower in the U.S. 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 2008 generated a profit of $173.3 million compared to a profit of $233.1 million in the 2007 period. In North America, the 2008 profit of $97.3 million was significantly lower than the 2007 profit of $205.6 million. Current year results were unfavorable mostly due to much weaker refining margins in 2008 compared to 2007. However, U.S. retail marketing margins improved in the 2008 period in comparison to 2007. The 2007 period included after-tax costs of $24.0 million related to closing 55 retail gasoline stations in North America. Results in the United Kingdom reflected earnings of $76.0 million in the first nine months of 2008 compared to earnings of $27.5 million in the 2007 period as 2008 benefitted from stronger refining margins on sale of petroleum products and a larger U.K. refining operation due to the Company’s purchase of the remaining 70% of the Milford Haven, Wales refinery in December 2007.
22
Refining and Marketing (Contd.)
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
Corporate activities, which include interest income and expense, foreign exchange effects, and corporate overhead not allocated to operating functions, had net costs of $31.3 million in the 2008 third quarter compared to net costs of $24.5 million in the third quarter of 2007. Net costs increased in 2008 compared to 2007 due to a combination of higher net interest expense associated with higher average borrowing levels and lower amounts capitalized to oil and gas development projects, and higher losses on foreign exchange. The Company capitalized most of its interest expense to the Kikeh oil development project in the third quarter of 2007.
For the first nine months of 2008, corporate activities reflected net costs of $95.8 million compared to net costs of $61.6 million a year ago. The increase in the nine-month costs for 2008 related to higher foreign exchange losses, higher net interest expense due mostly to lower interest capitalized to development projects, and higher administrative costs. Total after-tax costs for foreign currency exchange movements were $27.9 million in the 2008 nine-month period compared to $7.3 million in the same 2007 period.
Financial Condition and Liquidity
At September 30, 2008, the Company’s total Cash and Cash Equivalents was $828.1 million, and Canadian Government Securities with Maturities Greater than 90 Days at the Date of Acquisition totaled another $611.1 million. The Company has a committed revolving loan facility with 25 U.S. and foreign banks totaling $1.962 billion, of which $1.494 billion was unused at September 30, 2008. The capacity of the committed loan facility is reduced to $1.905 billion between June 2010 and June 2011 and is further reduced to $1.828 billion from June 2011 to maturity in June 2012. Based on currently available information, the Company does not anticipate any banks being unable to meet their obligations under the committed facility should the Company need to borrow under the facilities. The Company also has uncommitted loan facilities of approximately $100 million U.S. dollar equivalents; no amounts were borrowed under these facilities at September 30, 2008. There is no guarantee that the Company could access borrowings under these uncommitted loan facilities. The Company does not anticipate any banks that hold Company cash and any governments that have issued debt securities owned by the Company failing to meet their obligations. The Company believes that with its present cash, invested cash and loan facilities there is adequate sources of financing to meet its anticipated needs. The Company has not experienced any significant credit related losses.
23
Financial Condition and Liquidity (Contd.)
Net cash provided by operating activities was $2.597 billion for the first nine months of 2008 compared to $915.0 million during the same period in 2007. Changes in operating working capital other than cash and cash equivalents provided cash of $184.5 million in the first nine months of 2008, but used cash of $199.6 million in the 2007 period.
Other predominant uses of cash in both years were for dividends, which totaled $118.8 million in 2008 and $91.8 million in 2007, and for property additions and dry holes, which, including amounts expensed, were $1.560 billion and $1.279 billion in the nine-month periods ended September 30, 2008 and 2007, respectively. Total capital expenditures were as follows:
Capital Expenditures
Corporate and other
Total capital expenditures
Working capital (total current assets less total current liabilities) at September 30, 2008 was $1.329 billion, up $551 million from December 31, 2007. 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 $981 million below fair value at September 30, 2008.
At September 30, 2008, long-term notes payable of $1.066 billion had been reduced by $450 million compared to December 31, 2007. A summary of capital employed at September 30, 2008 and December 31, 2007 follows.
Capital employed
Total capital employed
The Company’s ratio of earnings to fixed charges was 32.3 to 1 for the nine-month period ended September 30, 2008.
Accounting and Other Matters
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS No. 159). This pronouncement permits companies with eligible financial assets and financial liabilities to measure these items at fair value in the financial statements. This option to measure at fair value is both instrument specific and irrevocable. If the fair value option is elected, certain additional disclosures are required and financial statements for periods prior to the adoption may not be restated. This pronouncement was effective January 1, 2008 for the Company. The Company chose not to elect fair value measurement for any financial assets and financial liabilities, and therefore, the adoption of SFAS No. 159, had no impact on the Company’s consolidated balance sheet or consolidated statement of income.
24
Accounting and Other Matters (Contd.)
In June 2007, the FASB ratified the Emerging Issues Task Force’s Issue No. 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards (EITF 06-11). This new guidance was effective for the Company beginning January 1, 2008 and required that income tax benefits received by the Company for dividends paid on share-based incentive awards be recorded in Capital in Excess of Par Value in Stockholders’ Equity. Under certain circumstances, such tax benefits received on awards that do not vest could be reclassified to reduce income tax expense in the Consolidated Statements of Income. The effect of adopting EITF No. 06-11 was not material to the Company’s consolidated financial statements.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations. This statement establishes 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 establishes how to recognize and measure goodwill acquired in the business combination or a gain from a bargain purchase, if applicable. This statement shall be applied prospectively by the Company to any business combination that occurs on or after January 1, 2009. Early application is prohibited. Assets and liabilities that arise from business combinations occurring prior to 2009 shall not be adjusted upon application of this statement. This statement will impact the recognition and measurement of assets and liabilities in business combinations that occur after 2008, and the Company is unable to predict at this time how the application of this statement will affect its financial statements in future periods.
In March 2008, the FASB issued SFAS No. 161, Disclosure about Derivative Instruments and Hedging Activities. This statement is effective for the Company beginning in January 2009, and it expands required disclosures regarding derivative instruments to include qualitative information about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. The Company does not expect this statement to have a significant effect on its consolidated financial statements.
Murphy holds a 20% interest in Block 16 Ecuador, where the Company and its partners produce oil for export. On October 18, 2007, the government of Ecuador enacted into law a levy that increases from 50% to 99% its share of oil sales prices that exceed a threshold reference price that was about $24.31 per barrel at September 30, 2008. The Company and its partners in Block 16 have filed for arbitration with an international arbitrator as permitted by its participation contract. The Company has also filed for arbitration under the bilateral investment treaty between the U.S. and Ecuador. While arbitration proceedings are ongoing the Block 16 partners have been negotiating contractual changes with the Ecuadorian government. Such negotiations have thus far been unsuccessful. In October 2008 the government of Ecuador notified the Company and its partners that a new contract must be agreed to or the government will terminate the contract. Further discussions with the government are expected. Commencing with the April 2008 revenue sharing, which was scheduled to be paid in June 2008, the Company and its partners ceased to pay any of the 99% revenue sharing to the Ecuadorian government pending the completion of arbitration proceedings. The Company continues to reduce its recorded revenue and has accrued a liability of $77.2 million at September 30, 2008 for the entire 99% revenue sharing without prejudice to the claims in the arbitration. Should the arbitration, negotiations and other designated security arrangements fail to permit the Company to recover its investment, the Company could have to record an impairment charge to reduce its investment in Block 16 in a future period. The Company’s carrying value of fixed assets in Ecuador at September 30, 2008 amounted to $80.1 million.
25
Outlook
Worldwide crude oil and North American natural gas prices have weakened considerably in October 2008 compared to the average price during the third quarter of 2008. The Company’s consolidated net income is expected to be unfavorably impacted by these significant price declines for oil and natural gas. The Company expects its oil and natural gas production to average about 141,000 barrels of oil equivalent per day in the fourth quarter. Following Hurricanes Gustav and Ike in the third quarter 2008, certain oil and natural gas production in the Gulf of Mexico remains shut-in in October and early November pending restart of pipelines owned and operated by other companies. During October 2008, U.S. retail marketing margins had improved due to falling wholesale gasoline prices, but refining margins have been relatively weak due to lower demand for refined products. The Company currently anticipates total capital expenditures for the full year 2008 to be approximately $2.4 billion.
Forward-Looking Statements
This Form 10-Q report contains statements of the Company’s expectations, intentions, plans and beliefs that are forward-looking and are dependent on certain events, risks and uncertainties that may be outside of the Company’s control. These forward-looking statements are made in reliance upon the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Actual results and developments could differ materially from those expressed or implied by such statements due to a number of factors including those described in the context of such forward-looking statements as well as those contained in the Company’s January 15, 1997 Form 8-K report on file with the U.S. Securities and Exchange Commission.
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 F 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 derivative contracts in place at September 30, 2008 to hedge the cost of about 1.8 million barrels of crude oil at the Meraux refinery. A 10% increase in the price of West Texas Intermediate crude oil would have increased the liability associated with this derivative contract by approximately $0.6 million, while a 10% decrease would have reduced the asset by a similar amount.
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, 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
26
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 matters referred to in this item is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
The Company has not identified any additional risk factors not previously disclosed in its Form 10-K filed on February 29, 2008.
27
28
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.
/s/ JOHN W. ECKART
November 7, 2008
(Date)
29
EXHIBIT INDEX
Exhibit No.
12.1*
31.1*
31.2*
32
Exhibits other than those listed above have been omitted since they are either not required or not applicable.
30