UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
For the quarterly period ended March 31, 2005
OR
For the transition period from to
Commission File Number 1-8590
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)
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 an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). x Yes ¨ No
Number of shares of Common Stock, $1.00 par value, outstanding at March 31, 2005 was 92,215,220.
PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
ASSETS
Current assets
Cash and cash equivalents
Short-term investments in marketable securities
Accounts receivable, less allowance for doubtful accounts of $13,951 in 2005 and $13,962 in 2004
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 $2,949,828 in 2005 and $2,933,214 in 2004
Goodwill, net
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
Total current liabilities
Notes payable
Nonrecourse debt of a subsidiary
Asset retirement obligations
Accrued major repair costs
Deferred credits and other liabilities
Stockholders’ equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued
Common Stock, par $1.00, authorized 200,000,000 shares, issued 94,613,379 shares
Capital in excess of par value
Retained earnings
Accumulated other comprehensive income
Unamortized restricted stock awards
Treasury stock, 2,398,159 shares of Common Stock in 2005 and 2,578,002 shares in 2004, at cost
Total stockholders’ equity
Total liabilities and stockholders’ equity
See Notes to Consolidated Financial Statements, page 6.
The Exhibit Index is on page 24.
1
CONSOLIDATED STATEMENTS OF INCOME (unaudited)
(Thousands of dollars, except per share amounts)
Three Months Ended
March 31,
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
Accretion of asset retirement obligations
Interest expense
Interest capitalized
Total costs and expenses
Income from continuing operations before income taxes
Income tax expense
Income from continuing operations
Income from discontinued operations, net of tax
NET INCOME
INCOME PER COMMON SHARE – BASIC
Income from discontinued operations
NET INCOME – BASIC
INCOME PER COMMON SHARE – DILUTED
NET INCOME – DILUTED
Average common shares outstanding – basic
Average common shares outstanding – diluted
2
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)
Net income
Other comprehensive income (loss), net of tax
Cash flow hedges
Net derivative gains (losses)
Reclassification to income
Total cash flow hedges
Net loss from foreign currency translation
COMPREHENSIVE INCOME
3
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
OPERATING ACTIVITIES
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Provisions for major repairs
Expenditures for major repairs and 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 operating working capital other than cash and cash equivalents
Other
Net cash provided by continuing operations
Net cash provided by discontinued operations
Net cash provided by operating activities
INVESTING ACTIVITIES
Property additions and dry hole costs
Proceeds from sales of assets
Proceeds from maturities of marketable securities
Other – net
Investing activities of discontinued operations
Net cash required by investing activities
FINANCING ACTIVITIES
Decrease in notes payable
Decrease in nonrecourse debt of a subsidiary
Proceeds from exercise of stock options and employee stock purchase plans
Cash dividends paid
Net cash used in financing activities
Effect of exchange rate changes on cash and cash equivalents
Net (decrease) increase in cash and cash equivalents
Cash and cash equivalents at January 1
Cash and cash equivalents at March 31
SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid
Interest capitalized in excess of amounts paid
4
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued
Common Stock – par $1.00, authorized 200,000,000 shares, issued 94,613,379 shares
Balance at beginning and end of period
Capital in Excess of Par Value
Balance at beginning of period
Exercise of stock options, including income tax benefits
Restricted stock transactions and other
Sale of stock under employee stock purchase plans
Balance at end period
Retained Earnings
Net income for the period
Cash dividends
Balance at end of period
Accumulated Other Comprehensive Income
Foreign currency translation losses, net of income taxes
Cash flow hedging losses, net of income taxes
Unamortized Restricted Stock Awards
Stock awards
Amortization, forfeitures and changes in price of Common Stock
Treasury Stock
Exercise of stock options
Awarded restricted stock, net of forfeitures
Total Stockholders’ Equity
See notes to consolidated financial statements, page 6.
5
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 1 through 5 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, 2004. In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at March 31, 2005, and the results of operations and cash flows for the three-month periods ended March 31, 2005 and 2004, 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 of America, 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 2004 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three months ended March 31, 2005 are not necessarily indicative of future results.
Note B – Discontinued Operations
The Company sold most of its Western Canadian conventional oil and gas assets (sale properties) in the second quarter 2004 for net proceeds of $583 million. At the time of the sale, the sale properties produced about 20,000 barrels of oil equivalent per day. The operating results from the sale properties have been reported as discontinued operations in 2004.
Revenues from the sale properties in the first quarter of 2004 were $52.7 million. Pretax earnings from the sale properties were $28.9 million in the first quarter of 2004 and income tax expense associated with discontinued operations amounted to $11.4 million in the 2004 period.
Note C – Employee and Retiree Pension and Postretirement Plans
The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors’ plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.
The table that follows provides the components of net periodic benefit expense for the three-month periods ended March 31, 2005 and 2004.
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
Murphy previously disclosed in its financial statements for the year ended December 31, 2004, that it expected to contribute $12.1 million to its defined benefit pension plans and $2.9 million to its postretirement benefits plan during 2005. During the three month period ended March 31, 2005, the Company made contributions of $7.2 million and remaining funding for the 2005 year for the Company’s domestic and foreign defined benefit pension and postretirement plans is anticipated to be $7.8 million.
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C – Employee and Retiree Benefit Plans (Contd.)
On December 8, 2003, the President signed the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). Among other provisions, the Act will provide prescription drug coverage under Medicare beginning in 2006. Generally, companies that provide qualifying prescription drug coverage that is deemed actuarially equivalent to medicare coverage for retirees aged 65 and above will be eligible to receive a federal subsidy equal to 28% of drug costs between $250 and $5,000 per annum for each covered individual that does not elect to receive coverage under the new prescription drug Medicare Part D. The Company currently provides prescription drug coverage to qualifying retirees under its retiree medical plan. The Company recognized $.4 million and $.1 million in estimated benefits related to the Act in the first quarters of 2005 and 2004, respectively.
Note D – Financial Instruments and Risk Management
Murphy 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 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.
7
Note D – Financial Instruments and Risk Management (Contd.)
During the next twelve months, the Company expects to reclassify approximately $2.6 million in net after-tax losses from AOCI into earnings as the forecasted transactions covered by hedging instruments actually occur. All forecasted transactions currently being hedged are expected to occur by December 2006.
Note E – Earnings per Share and Stock Options
Net income was used as the numerator in computing both basic and diluted income per Common share for the three months ended March 31, 2005 and 2004. The following table reconciles the weighted-average shares outstanding used for these computations.
March 31
(Weighted-average shares)
Basic method
Dilutive stock options
Diluted method
There were no antidilutive options for the periods ended March 31, 2005 and 2004.
Through March 2005, the Company used the intrinsic-value based method of accounting as prescribed by Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations to account for its stock options. Under this method, the Company accrues costs of restricted stock and any stock option deemed to be variable in nature over the vesting/performance period and adjusts such costs for changes in the fair market value of Common Stock. No compensation expense is recorded for fixed stock options since all option prices have been equal to or greater than the fair market value of the Company’s stock on the date of grant. The Financial Accounting Standards Board (FASB) has issued Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), Share Based Payment, which replaces SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. SFAS No. 123 (revised 2004) 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. In April 2005, the Securities and Exchange Commission adopted a new rule allowing statement implementation for the Company to be deferred until January 1, 2006. The Company is currently evaluating which fair value measurement method to use and whether to use the modified retrospective application or modified prospective application upon adoption. Had the Company recorded compensation expense for stock options as prescribed by SFAS No. 123, net income and earnings per share for the three-month periods ended March 31, 2005 and 2004, would be the pro forma amounts shown in the following table.
(Thousands of dollars except per share data)
Net income – As reported
Restricted stock compensation expense included in income, net of tax
Total stock-based compensation expense using fair value method for all awards, net of tax
Net income – Pro forma
Net income per share – As reported, basic
Pro forma, basic
As reported, diluted
Pro forma, diluted
In the first quarter 2005, the Company granted 467,500 options with an exercise price of $90.45 per share, and also granted 179,475 additional shares of performance-based and time-based restricted stock.
8
Note F – Accumulated Other Comprehensive Income
The components of Accumulated Other Comprehensive Income (AOCI) on the Consolidated Balance Sheets at March 31, 2005 and December 31, 2004 are presented in the following table.
Foreign currency translation, net
Cash flow hedging, net
Minimum pension liability, net
The effect of SFAS Nos. 133/138, Accounting for Derivative Investments and Hedging Activities, decreased AOCI for the three months ended March 31, 2005 by $14.3 million, net of $5.9 million in income taxes, and hedging ineffectiveness was not significant. The AOCI decrease in the first quarter 2005 was primarily related to the change in fair value of blended heavy oil forward sales contracts described in Note D. Derivative instruments decreased AOCI for the three months ended March 31, 2004 by $.7 million, net of $.4 million in income taxes, and hedging ineffectiveness was not significant.
Note G – Environmental Contingencies
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 80 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.
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 two 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 both 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 two 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 future net income, financial condition or liquidity.
Note H – 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
9
Note H – Other Contingencies (Contd.)
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 December 2000, two of the Company’s Canadian subsidiaries, Murphy Oil Company Ltd. (MOCL) and Murphy Canada Exploration Company (MCEC) as plaintiffs filed an action in the Court of Queen’s Bench of Alberta seeking a constructive trust over oil and gas leasehold rights to Crown lands in British Columbia. The suit alleges that the defendants, The Predator Corporation Ltd. and Predator Energies Partnership (collectively Predator) and Ricks Nova Scotia Co. (Ricks), acquired the lands after first inappropriately obtaining confidential and proprietary data belonging to the Company and its partner. In January 2001, Ricks, representing an undivided 75% interest in the lands in question, settled its portion of the litigation by conveying its interest to the Company and its partner at cost. In 2001, Predator, representing the remaining undivided 25% of the lands in question, filed a counterclaim, as subsequently amended, against MOCL and MCEC and MOCL’s President individually seeking compensatory damages of C$3.61 billion. In September 2004 the court summarily dismissed all claims against MOCL’s president and all but C$356 million of the counterclaim against the Company; however, this dismissal order is currently on appeal. The Company believes that the counterclaim is without merit, that the amount of damages sought is frivolous and the likelihood of a material loss to the Company is remote. It is anticipated that a trial concerning the 25% disputed interest and any remaining issues will commence in 2005. While the litigation is in the discovery stage and no assurance can be given about the outcome, the Company does not believe that the ultimate resolution of this suit will have a material adverse effect on its net income, financial condition or liquidity in a future period. In the unlikely event that Predator were to prevail in its counterclaim in an amount approaching the damages sought, Murphy would incur a material expense in its consolidated statement of income, and would have a material effect on its financial condition and liquidity.
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. 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 class action 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.
On March 5, 2002, two of the Company’s subsidiaries filed suit in the Court of Queen’s Bench, Alberta, against Enron Canada Corp. (Enron) to collect $2.1 million owed to Murphy under canceled gas sales contracts. On May 1, 2002, Enron counterclaimed for $19.8 million allegedly owed by Murphy under those same agreements. By an agreement entered into on May 4, 2005, the parties agreed to a compromise and settlement of the litigation with no admission of liability by either side. The resolution of this matter had no effect on the Company’s net income, financial condition or liquidity in the first quarter of 2005 and is not expected to have a material effect on these measures in any 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 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 March 31, 2005, the Company had contingent liabilities of $8.5 million under a financial guarantee and $55.4 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.
10
Note I – Business Segments
(Millions of dollars)
Total Assets
at March 31,
2005
External
Revenues
Interseg.
Income
(Loss)
Exploration and production*
United States
Canada
United Kingdom
Ecuador
Malaysia
Total
Refining and marketing
North America
Total operating segments
Corporate and other
Total from continuing operations
Discontinued operations
Note J – Accounting Matters
The FASB has issued FASB Staff Position (FSP) 19-1 to provide guidance on the accounting for exploratory well costs and to amend SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies. The guidance in FSP 19-1 applies to companies that use the successful efforts method of accounting as described in SFAS No. 19. This FSP 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 validity of the project. The guidance in this FSP is to be applied beginning in April 2005. The guidance will be applied prospectively to existing and newly-capitalized exploratory well costs. However, any capitalized well costs that do not meet the requirements of the FSP must be written off upon its adoption. The proposed FSP as written requires additional disclosures related to capitalized costs. The Company does not expect the adoption of this FSP to have any effect on its net income or financial condition.
In October 2004, the President of the United States signed into law the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (the “Act”). The FASB issued FSP 109-1 in December 2004 to provide guidance on the application of SFAS No. 109, Accounting for Income Taxes, to the provision within the Act that will ultimately provide a tax deduction of up to 9% on qualified production activities. The tax deduction phases in at 3% beginning in 2005 and reaches 9% in 2010. FSP 109-1 concluded that the deduction should be accounted for as a special deduction in accordance with SFAS 109, whereby the tax benefit is recognized as realized, rather than as a one-time benefit due to a reduction of deferred tax liabilities. This FSP was effective upon issuance. The Company recorded a tax benefit of approximately $.6 million in the three-month period ended March 31, 2005 related to the Act.
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Note J – Accounting Matters (Contd.)
The EITF has issued EITF 03-13, Applying the Conditions in Paragraph 42 of SFAS No. 144 in Determining Whether to Report Discontinued Operations. The EITF generally believes that current practice with respect to applying the criteria in paragraph 42 of SFAS No. 144 has not been applied consistently and has not resulted in broadening the reporting of asset dispositions as discontinued operations. EITF 03-13 contains further guidance for evaluating the cash flows of the component sold and what constitutes significant continuing involvement. This standard must be applied to all asset disposal transactions occurring after January 1, 2005. In certain industries, EITF 03-13 may lead to more asset disposals being reported as discontinued operations in future periods. However, in the oil and gas industry, it may cause more asset disposals to continue to be classified as continuing operations due to clarification of what constitutes continuing involvement.
SFAS No. 151, Inventory Costs, was issued by the FASB in November 2004. This statement amends Accounting Research Bulletin No. 43, to clarify that abnormal amounts of idle facility expense, freight, handling costs, and wasted materials should be recognized as current-period charges, and it also requires that allocation of fixed production overheads be based on the normal capacity of the related production facilities. The provisions of this statement will be effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The provisions of this statement will be applied prospectively. The Company does not expect the adoption of this statement to have a significant impact on its results of operations.
The FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets an amendment of APB Opinion No. 29, in December 2004. This statement addresses the measurement of exchanges of nonmonetary assets and eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. The provisions of SFAS No. 153 will be effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The provisions of this statement will be applied prospectively. The Company does not expect the adoption of this statement to have a significant impact on its results of operations.
In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS No. 143. This interpretation clarifies the term conditional asset retirement obligation as used in SFAS No. 143 and when a company would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. This interpretation is effective for fiscal years ending after December 15, 2005. The Company is currently evaluating whether the adoption of this interpretation will have any effect on its financial statements.
In March 2005, the Emerging Issues Task Force decided in Issue 04-6 that mining operations should account for post-production stripping costs as a variable production cost that should be considered a component of mineral inventory costs. The Company’s synthetic oil operations at Syncrude may be affected by this ruling. The EITF consensus is effective for fiscal years beginning after December 15, 2005 and any adjustment required as of the January 1, 2006 effective application date for the Company will be recorded as a cumulative effect of a change in accounting principle. The Company is currently evaluating the accounting implications of this new EITF consensus.
Note K – Subsequent Event
In the first quarter of 2005, the Company determined that it would attempt to sell certain oil and natural gas properties on the continental shelf of the Gulf of Mexico, and on May 6 the Company entered into an agreement to sell such properties for a sale price of approximately $182.5 million. The Company expects to complete the sale transaction in the second quarter of 2005. At March 31, 2005, the assets to be sold had a net book value of $33.1 million and an associated asset retirement obligation liability of $46.4 million.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Results of Operations
Murphy’s net income in the first quarter of 2005 was $113.2 million, $1.20 a diluted share, compared to net income of $98.2 million, $1.05 per diluted share, in the same quarter a year ago. Income from discontinued operations was $17.5 million, $.19 per share, in the 2004 first quarter related to results of certain conventional oil and gas properties in Western Canada that were sold in the second quarter of last year. First quarter income from continuing operations was $113.2 million, $1.20 per share, in 2005 and $80.7 million, $.86 per diluted share, in 2004. The improvement in the 2005 period was mostly attributable to higher exploration and production earnings and lower net costs from corporate activities. Murphy’s net income by operating segment is presented below.
Exploration and production
Corporate
Murphy’s income from continuing exploration and production operations was $124.9 million in the first quarter of 2005 compared to $101.2 million in the first quarter a year ago. Higher realized sales prices for crude oil and natural gas and higher crude oil sales volumes were the primary reasons for improved earnings. Partially offsetting the improvements in prices and volumes were higher exploration expenses, which increased from $49.1 million in the 2004 period to $70.3 million in 2005. The increase in exploration expense in 2005 was primarily caused by two dry holes in the Republic of Congo following a discovery at the Azurite Marine #1 well in January 2005. In the United States, higher exploration costs for 3-D seismic and leasehold amortization was mostly offset by lower deepwater Gulf of Mexico dry hole costs. The first quarter of 2004 included a $15.4 million after-tax gain on disposal of the Simsboro and Sligo onshore natural gas properties in the United States. The Company’s refining and marketing operations incurred a loss of $5.5 million in the 2005 quarter compared to a loss of $6.4 million in the 2004 quarter. Corporate functions reflected a loss of $6.2 million in the 2005 quarter compared to a loss of $14.1 million in the same period in 2004. The 2005 period included higher interest income related to a settlement of U.S. tax matters, higher gains on foreign exchange, and less net interest expense due to a combination of lower average outstanding debt and higher interest capitalized on development projects. These favorable variances were partially offset by more administrative costs, primarily for stock-based compensation associated with a higher Company-share price in the 2005 period. The Company’s overall effective income tax rate was 44.3% during the first quarter 2005, and was higher than the U.S. statutory income tax rate primarily because no income tax benefits were recorded during this period for dry holes drilled offshore the Republic of Congo and Block H, Malaysia.
Exploration and Production
Results of continuing exploration and production operations are presented by geographic segment below.
Other International
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (Contd.)
Exploration and Production (Contd.)
Exploration and production operations in the United States reported record quarterly earnings of $61.9 million in the first quarter of 2005 compared to $36.5 million in the 2004 quarter. This increase was due to higher crude oil and natural gas sales volumes, primarily from the Medusa and Front Runner fields, and higher crude oil and natural gas sales prices. Production expenses and depreciation expense increased mostly due to higher crude oil and natural gas sales volumes. Exploration expense decreased $3.4 million versus the prior period primarily due to decreased dry hole costs in the deepwater Gulf of Mexico partially offset by increased geological and geophysical costs in the 2005 period. The 2004 period benefited from a $15.4 million after-tax gain on the disposal of two natural gas properties onshore United States.
Earnings from continuing operations in Canada were $55.4 million in the 2005 quarter versus $53.6 million in the 2004 quarter. While Canadian operations received higher crude oil and natural gas sales prices in the current period, this was tempered by decreased offshore oil and synthetic oil sales volumes. Production expense and depreciation expense increased in the most recent period due to higher heavy oil production partially offset by lower offshore sales volumes.
U.K. operations earned $17.0 million in the 2005 period versus $13.8 million in the same quarter a year ago. Lower sales volumes for crude oil were more than offset by higher realized selling prices during the period and lower production and depreciation expense. The Company sold its interest in the “T” Block field in the U.K. North Sea in September 2004.
Operations in Ecuador earned $5.2 million in 2005 compared to $2.9 million a year ago. The improved results were primarily due to higher sales volumes and prices. Income tax expense was $4.8 million in 2005 and $2.6 million in 2004. The current period included a $.9 million tax adjustment relating to settlement of prior years tax returns. The Company recommenced sales of its current oil production from Block 16 in Ecuador in the first quarter of 2005, but has thus far achieved no settlement with the other owners related to the Company’s entitlement of approximately 1.5 million barrels that were withheld by the operator in 2004 during a dispute over Murphy’s new transportation and marketing arrangement.
Malaysia reported earnings of $9.7 million in the first quarter of 2005 compared to a loss of $4.0 million in the same period in 2004. The improvement in the current period was due to increased oil sales volumes and prices. Production expense and depreciation increased as a result of the higher sales volumes. Exploration expenses increased $3.1 million in the 2005 period primarily due to higher dry hole and seismic costs.
Other international operations reported a loss of $24.3 million in the 2005 period versus a loss of $1.6 million in the same period a year ago. The higher loss was primarily due to expensing two dry holes in the Republic of Congo in the current period.
On a worldwide basis, the Company’s crude oil and condensate sales price averaged $39.90 per barrel for the current quarter compared to $30.95 per barrel in the first quarter of 2004. Average crude oil and liquids production from continuing operations was 108,738 barrels per day, up 13,610 barrels per day or 14% over the 2004 period. Average oil sales volumes increased 16% to 108,894 barrels per day. The increase in crude oil production volumes was mostly attributable to higher production at the Medusa field and new production at the Front Runner field, both of which are in the deepwater Gulf of Mexico. North American natural gas sales prices averaged $6.71 per thousand cubic feet (MCF) in the most recent quarter compared to $5.88 per MCF in the same quarter of 2004. Total natural gas sales volumes from continuing operations averaged 112 million cubic feet per day in 2005, down from 124 million cubic feet per day in the same period a year ago. The decrease was primarily attributable to Viosca Knoll Block 783 production being offline for much of the just completed quarter following damages incurred in 2004 from Hurricane Ivan.
Additional details about results of oil and gas operations are presented in the tables on page 16.
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Selected operating statistics for the three-month periods ended March 31, 2005 and 2004 follow.
Net crude oil, condensate and gas liquids produced – barrels per day
Continuing operations
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)
Total net hydrocarbons produced from continuing operations – equivalent barrels per day (1)
Total net hydrocarbons sold from continuing operations – equivalent barrels per day (1)
Weighted average sales prices
Crude oil and condensate – dollars per barrel (2)
Canada (3) – light
– heavy (4)
Natural gas – dollars per thousand cubic feet
United States (2)
Canada (3)
United Kingdom (3)
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CONTINUING OIL AND GAS OPERATING RESULTS (unaudited)
United
Kingdom
Three Months Ended March 31, 2005
Oil and gas sales and other operating revenues
Production expenses
Exploration expenses
Dry holes
Geological and geophysical
Undeveloped lease amortization
Total exploration expenses
Income tax provisions
Results of operations (excluding corporate overhead and interest)
Three Months Ended March 31, 2004
Income tax provisions (benefits)
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Refining and Marketing
Results of refining and marketing operations are presented below by geographic segment.
Refining and marketing operations in North America reported a loss of $8.3 million during the first quarter of 2005 compared to a loss of $10.5 million in the same period a year ago. The smaller loss was primarily attributable to better performance and margins at the Meraux refinery. However, margins for the Company’s U.S. retail gasoline system were lower and were hurt by rising wholesale gasoline prices during much of the current period. The first quarter 2004 results included a net after-tax gain of $3 million from sale of the Company’s jointly owned terminals in the U.S. Refining and marketing operations in the U.K. earned $2.8 million in the 2005 period, down from a $4.1 million profit in the same quarter of 2004, with the weaker results based on operating margins that were squeezed by higher crude prices during the 2005 period. Worldwide refinery inputs were 182,304 barrels per day in the first quarter of 2005 compared to 170,888 barrels per day in the 2004 quarter. The 2005 quarter was higher primarily due to better performance at the Company’s Meraux refinery. Petroleum product sales were 357,044 barrels per day, up from 301,718 a year ago. The Company was operating 118 more gasoline stations at Wal-Mart sites at March 31, 2005 compared to March 31, 2004.
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 and corporate overhead not allocated to operating functions, reported a loss of $6.2 million in the 2005 quarter compared to a loss of $14.1 million in the first quarter of 2004. The 2005 period included higher interest income related to a settlement of U.S tax matters, higher gains on foreign exchange, and less net interest expense due to a combination of lower average outstanding debt and higher interest capitalized on development projects. These favorable variances were partially offset by more administrative costs, primarily for stock-based compensation associated with a higher Company-share price in the 2005 period.
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Financial Condition
Net cash provided by continuing operating activities was $206.6 million for the first three months of 2005 compared to $265.7 million during the same period in 2004. Changes in operating working capital other than cash and cash equivalents used cash of $57.3 million in the first quarter of 2005 and provided cash of $75.2 million in the 2004 period.
Other predominant uses of cash in both years were for dividends, which totaled $20.7 million in 2005 and $18.4 million in 2004, and for capital expenditures, which, including amounts expensed, are summarized in the following table.
Capital expenditures – continuing operations
Total capital expenditures – continuing operations
Geological, geophysical and other exploration expenses charged to income
Total property additions and dry holes – continuing operations
Working capital (total current assets less total current liabilities) at March 31, 2005 was $401.8 million, down $22.6 million from December 31, 2004. 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 $324.6 million below fair value at March 31, 2005.
At March 31, 2005, long-term notes payable of $597.8 million and long-term nonrecourse debt of a subsidiary of $15.5 million were virtually unchanged from December 31, 2004. A summary of capital employed at March 31, 2005 and December 31, 2004 follows.
Capital Employed
Total capital employed
Accounting and Other Matters
The FASB has issued FASB Staff Position (FSP) 19-1 to provide guidance on the accounting for exploratory well costs and to amend SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies. The guidance in FSP 19-1 applies to companies that use the successful efforts method of accounting as described in SFAS No. 19. This FSP 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 validity of the project. The guidance in this FSP is to be applied beginning in April 2005. The guidance will be applied prospectively to existing and newly-capitalized exploratory well costs. However, any capitalized well costs that do not meet the requirements of the FSP must be written off upon its adoption. The proposed FSP as written requires additional disclosures related to capitalized costs. The Company does not expect the adoption of this FSP to have any effect on its net income.
In October 2004, the President of the United States signed into law the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (the “Act”). The FASB issued FSP 109-1 in December 2004 to provide guidance on the application of SFAS No. 109, Accounting for Income Taxes, to the provision within the Act that will ultimately provide a tax deduction of up to 9% on qualified production activities.
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Accounting and Other Matters (Contd.)
The tax deduction phases in at 3% beginning in 2005 and reaches 9% in 2010. FSP 109-1 concluded that the deduction should be accounted for as a special deduction in accordance with SFAS 109, whereby the tax benefit is recognized as realized, rather than as a one-time benefit due to a reduction of deferred tax liabilities. This FSP was effective upon issuance. The Company recorded a tax benefit of approximately $.6 million in the three-month period ended March 31, 2005 related to the Act.
The EITF has issued issued EITF 03-13, Applying the Conditions in Paragraph 42 of SFAS No. 144 in Determining Whether to Report Discontinued Operations. The EITF generally believes that current practice with respect to applying the criteria in paragraph 42 of SFAS No. 144 has not been applied consistently and has not resulted in broadening the reporting of asset dispositions as discontinued operations. EITF 03-13 contains further guidance for evaluating the cash flows of the component sold and what constitutes significant continuing involvement. This standard must be applied to all asset disposal transactions occurring after January 1, 2005. In certain industries, EITF 03-13 may lead to more asset disposals being reported as discontinued operations in future periods. However, in the oil and gas industry, it may cause more asset disposals to continue to be classified as continuing operations due to clarification of what constitutes continuing involvement.
In March 2005 the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS No. 143. This interpretation clarifies the term conditional asset retirement obligation as used in SFAS No. 143 and when a company would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. This interpretation is effective for fiscal years ending after December 15, 2005. The Company is currently evaluating whether the adoption of this interpretation will have any effect on its financial statements.
Murphy holds a 20% interest in Block 16 Ecuador, where the Company and its partners produce oil for export. In 2001, the local tax authorities announced that Value Added Taxes (VAT) paid on goods and services related to Block 16 and many oil fields held by other companies will no longer be reimbursed. In response to this announcement, oil producers have filed actions in the Ecuador Tax Court seeking determination that the VAT in question is reimbursable. In July 2004, international arbitrators ruled that VAT was recoverable by another oil company, but the State of Ecuador responded that it was not bound by this arbitral decision. As of March 31, 2005, the Company has a receivable of approximately $12.3 million related to VAT. Murphy believes that its claim for reimbursement of VAT under applicable Ecuador tax law is valid, and it does not expect that the resolution of this matter will have a material adverse affect on the Company’s net income, financial condition or liquidity in future periods.
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Outlook
Crude oil and natural gas sales prices have remained strong during April 2005. Production is expected to average approximately 126,000 barrels of oil equivalent per day in the second quarter 2005. Production from the Front Runner field in the deepwater Gulf of Mexico will ramp up during 2005 as new wells are brought on stream. North American refining and marketing margins have strengthened early in the second quarter 2005 compared to the just completed first quarter. The Company currently anticipates total capital expenditures in 2005 of approximately $1.2 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.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note D to this Form 10-Q report, Murphy makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.
Murphy was a party to natural gas price swap agreements at March 31, 2005 for a remaining notional volume of 1.8 million MMBTU that are intended to hedge the financial exposure of its Meraux, Louisiana refinery to fluctuations in the future price of a portion of natural gas to be purchased for fuel in 2005 and 2006. In each month of settlement, the swaps require Murphy to pay an average natural gas price of $3.35 per MMBTU and to receive the average NYMEX price for the final three trading days of the month. At March 31, 2005, the estimated fair value of these agreements was recorded as an asset of $7.8 million. A 10% increase in the average NYMEX price of natural gas would have increased this asset by $1.3 million, while a 10% decrease would have reduced the asset by a similar amount.
At March 31, 2005, the Company was a party to forward sale contracts covering 2,000 barrels per day in blended heavy oil sales during 2005 and 4,000 barrels per day in 2006. The contracts are intended to hedge the financial exposure of the Company’s blended heavy oil sales in Canada during the respective contract period and are priced at $29.00 per barrel in 2005 and $25.23 per barrel in 2006. At March 31, 2005, the estimated fair value of these agreements was recorded as a $21.5 million liability. A 10% increase in the price of Canadian heavy oil at the Hardisty terminal in Canada would have increased this liability by $7.4 million, while a 10% decrease would have decreased this liability by a similar amount.
ITEM 4. CONTROLS AND PROCEDURES
Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.
Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
There were no significant changes in the Company’s internal controls over financial reporting that occurred during the first quarter of 2005 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting.
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PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
(Registrant)
/s/ JOHN W. ECKART
May 9, 2005
(Date)
(Chief Accounting Officer and DulyAuthorized Officer)
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EXHIBIT INDEX
Exhibits other than those listed above have been omitted since they are either not required or not applicable.
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