UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
For the quarterly period ended June 30, 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)
(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. Yes x No ¨
Indicate by check mark whether the registrant is an accelerated filer (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 June 30, 2005 was 184,430,478.
PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
June 30,
2005
December 31,
2004
ASSETS
Current assets
Cash and cash equivalents
Short-term investments in marketable securities
Accounts receivable, less allowance for doubtful accounts of $13,693 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 $2,250,260 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 450,000,000 shares at June 30, 2005 and 200,000,000 shares at December 31, 2004, issued 186,828,618 shares at June 30, 2005 and 94,613,379 shares at December 31, 2004
Capital in excess of par value
Retained earnings
Accumulated other comprehensive income
Unamortized restricted stock awards
Treasury stock, 2,398,140 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 29.
1
CONSOLIDATED STATEMENTS OF INCOME (unaudited)
(Thousands of dollars except per share amounts)
Three Months Ended
Six Months Ended
REVENUES
Sales and other operating revenues
Gain on sale of assets
Interest and other income
Total revenues
COSTS AND EXPENSES
Crude oil 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 adjustments
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 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:
Sales proceeds
Net cash provided (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 increase (decrease) in cash and cash equivalents
Cash and cash equivalents at January 1
Cash and cash equivalents at June 30
SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid, net of refunds
Interest paid, net of amounts capitalized
4
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 at June 30, 2005 and 200,000,000 shares at June 30, 2004, issued 186,828,618 shares at June 30, 2005 and 94,613,379 shares at June 30, 2004
Balance at beginning of period
Two-for-one stock split effective June 3, 2005
Balance at end of period
Capital in Excess of Par Value
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
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 June 30, 2005, and the results of operations and cash flows for the three-month and six-month periods ended June 30, 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 six months ended June 30, 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.
The following table reflects the results of operations from the sale properties including the 2004 gain on sale.
Revenues, including a pretax gain on sale of assets of $190,390
Income before income tax expense
Note C – Property, Plant and Equipment
In June 2005, the Company completed the sale of mature oil and natural gas properties on the continental shelf of the Gulf of Mexico for a sale price of approximately $156.3 million after operating adjustments. Total net production from the properties sold amounted to approximately 4,000 barrels of oil equivalent per day during the six-month period ended June 30, 2005, and total net proved reserves at December 31, 2004 were 35.8 billion cubic feet of gas and 1.5 million barrels of oil. The assets sold had a net book value of $33.5 million and an associated asset retirement obligation liability of $44.8 million. The Company recorded a gain before income taxes of approximately $168.9 million on this transaction, which is included in Gain on Sale of Assets on the Consolidated Statement of Income.
During the six months ended June 30, 2004, the Company reported before tax gains of $30.8 million on sale of assets. The primary assets sold were certain natural gas fields onshore U.S. and all but one of the Company’s jointly owned marketing terminals in the United States.
The Financial Accounting Standards Board (FASB) has issued FASB Staff Position (FSP) 19-1 to provide guidance on the accounting for exploratory well costs and to amend Statement of Financial Accounting Standards (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 viability of the project. The guidance in this FSP was applied beginning in April 2005. The guidance was applied prospectively to existing and newly-capitalized exploratory well costs. The adoption of this FSP did not have any effect on the Company’s net income or financial condition.
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C – Property, Plant and Equipment (Contd.)
At June 30, 2005, the Company had total capitalized drilling costs pending the determination of proved reserves of $226.3 million. The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30, 2005 and 2004.
Beginning balance at January 1
Additions to capitalized exploratory well costs pending the determination of proved reserves
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves
Capitalized exploratory well costs charged to expense or sold
Ending balance at June 30
The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling.
Capitalized exploratory well costs capitalized for one year or less
Capitalized exploratory well costs capitalized for more than one year but less than two years
Capitalized exploratory well costs capitalized for more than two years but less than three years
Balance at June 30
Number of projects that have exploratory well costs that have been capitalized for one year or more
Note D – 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 unfunded health care and life insurance benefit plans that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.
7
Note D – Employee and Retiree Pension and Postretirement Plans (Contd.)
The table that follows provides the components of net periodic benefit expense for the three-month and six-month periods ended June 30, 2005 and 2004.
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service cost
Amortization of transitional asset
Recognized actuarial loss
Settlement gain
Net periodic benefit expense
Murphy previously disclosed in its financial statements for the year ended December 31, 2004, that it expected to make required and discretionary contributions totaling $12.1 million to its defined benefit pension plans and $2.9 million to its postretirement benefits plan during 2005. During the six-month period ended June 30, 2005, the Company made contributions of $9 million. Remaining funding in 2005 for the Company’s domestic and foreign defined benefit pension and postretirement plans is currently anticipated to be $6 million.
The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (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 $.7 million and $.4 million in estimated benefits related to the Act in the first half of 2005 and 2004, respectively.
Note E – Financing Arrangements
On June 14, 2005, Murphy entered into a five-year $1 billion committed credit facility, whereby the Company and certain wholly-owned subsidiaries may borrow funds from a major banking consortium. The new credit facility replaced two similar committed credit facilities with an aggregate borrowing capacity of $700 million. Borrowings under the new credit facility bear interest at prime or varying cost of fund options. Facility fees are due on the commitments. No amounts had been borrowed under this credit facility as of June 30, 2005.
8
Note F – 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.
During the next twelve months, the Company expects to reclassify approximately $8.3 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.
9
Note G – 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-month and six-month periods ended June 30, 2005 and 2004. All share amounts and per share amounts for all periods reflect the two-for-one stock split effective June 3, 2005. The following table reconciles the weighted-average shares outstanding used for these computations.
Basic method
Dilutive stock options
Diluted method
There were no antidilutive options for the three-month and six-month periods ended June 30, 2005 and 2004.
The Company uses 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 FASB has issued 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 this statement implementation for the Company to be deferred until January 1, 2006. The Company is currently evaluating which fair value measurement method to use in 2006 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 and six-month periods ended June 30, 2005 and 2004, would be the pro forma amounts shown in the following table.
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 935,000 options with an exercise price of $45.225 per share, and also granted 358,950 additional shares of performance-based and time-based restricted stock.
10
Note H – Accumulated Other Comprehensive Income
The components of Accumulated Other Comprehensive Income on the Consolidated Balance Sheets at June 30, 2005 and December 31, 2004 are presented in the following table.
Foreign currency translation gain
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 six months ended June 30, 2005 by $20 million, net of $8.6 million in income taxes, and hedging ineffectiveness was not significant. The AOCI decrease in the first half of 2005 was primarily related to the change in fair value of blended heavy oil forward sales contracts described in Note F. Derivative instruments decreased AOCI for the six months ended June 30, 2004 by $1.1 million, net of $.6 million in income taxes, and hedging ineffectiveness increased income by $.3 million, net of $.1 million in income taxes.
Note I – 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 within the Company’s asset retirement obligation liability.
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 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 to be incurred at known or currently unidentified sites is not expected to have a material adverse effect on its net income, financial condition or liquidity in a future period.
11
Note J – 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 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 2006. 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 an insignificant effect on the Company’s net income and financial condition in the first half of 2005.
12
Note J – Other Contingencies (Contd.)
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 June 30, 2005, the Company had contingent liabilities of $8.5 million under a financial guarantee and $104.2 million on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to the guarantee and letters of credit because it believes that the likelihood of having these drawn is remote.
13
Note K – Business Segments
June 30, 2005
June 30, 2004
(Millions of dollars)
Inter-
segmentRevenues
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
14
Note L – Accounting Matters
In October 2004 the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (the “Act”) became law. 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 $2.4 million in the six-month period ended June 30, 2005 related to the Act.
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.
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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 second quarter of 2005 was $347.7 million, $1.85 per diluted share, compared to net income of $349.9 million, $1.87 per diluted share, in the second quarter of 2004. Net income in the current period included an after-tax gain of $106.8 million on sale of mature oil and gas properties on the continental shelf of the Gulf of Mexico. Excluding the gain on property sale, normalized earnings in the second quarter 2005 were at record levels. Net income in the 2004 period included income from discontinued operations of $181.8 million, $.97 per diluted share, $166.7 million of which was an after-tax gain on sale of most conventional oil and gas assets in Western Canada. For the first six months of 2005, net income totaled $460.9 million, $2.46 per diluted share, compared to $448.1 million, $2.40 per diluted share, for the 2004 period. Murphy’s net income by operating segment is presented below.
Exploration and production
Corporate
In the current quarter, the Company’s exploration and production operations earned $289.9 million, an increase of $150.1 million from $139.8 million earned in the 2004 period. The earnings improvement in 2005 was primarily caused by a $106.8 million after-tax gain on sale of oil and gas properties in the Gulf of Mexico, higher oil and gas sales prices and higher oil sales volumes. These were somewhat offset by higher exploration expense and lower natural gas sales volumes in the 2005 quarter. Exploration expenses were $40 million in the second quarter of 2005 compared to $23.2 million in the same period of 2004, with the increase mostly due to higher 3-D seismic programs and dry hole costs in Malaysia and expenses associated with exploration activities in 2005 in the Republic of Congo. The Company’s refining and marketing operations generated a record quarterly profit of $67.4 million in the second quarter of 2005 compared to a profit of $39.5 million for the three months ended June 30, 2004. The improvement was due to significantly better refining margins in the United States in the current quarter. The after-tax costs of the corporate function were $9.6 million in the 2005 second quarter compared to $11.2 million in the 2004 quarter as lower net interest expense and higher foreign exchange gains more than offset higher administrative expenses in 2005.
For the first six months of 2005, income from continuing operations was $460.9 million, $2.46 per diluted share, compared to $248.8 million, $1.33 per diluted share, for the first half of 2004. Income from both exploration and production and refining and marketing businesses improved in 2005. The Company’s exploration and production continuing operations earned $414.8 million in the first half of 2005 and $241 million in the same period of 2004. The earnings improvement in 2005 was caused by a $106.8 million after-tax gain on sale of oil and gas properties in the Gulf of Mexico, higher oil and natural gas sales prices and higher oil sales volumes, partially offset by lower natural gas sales volumes and higher exploration expenses. Exploration expenses were $110.3 million in 2005 compared to $72.3 million in 2004, with the increase in the 2005 period mostly due to higher dry hole and 3-D seismic costs in Malaysia, and expenses associated with exploration activities in 2005 in the Republic of Congo. The Company’s refining and marketing operations generated income of $61.9 million in the first six months of 2005, compared to $33.1 million in the 2004 period. The improved current year result was based on stronger U.S. refining margins in 2005. Corporate after-tax costs were $15.8 million in the 2005 period compared to costs of $25.3 million in the 2004 period. Lower net interest expenses and higher foreign exchange gains in 2005 were partially offset by higher administrative costs in the current period.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (Contd.)
Exploration and Production
Results of continuing exploration and production operations are presented by geographic segment below.
Other International
Exploration and production operations in the United States reported earnings of $187.9 million in the second quarter of 2005 compared to earnings of $47.7 million a year ago. This improvement was primarily caused by the $106.8 million after-tax gain on sale of oil and gas properties in the Gulf of Mexico, higher oil and natural gas sales prices and higher oil sales volumes due to the start-up of the Front Runner field in deepwater Gulf of Mexico in the fourth quarter of 2004. Production expense increased due to higher oil sales volumes and higher workover costs. Depreciation expense increased mostly due to the higher crude oil sales volumes. Natural gas sales volumes decreased in the most recent quarter primarily due to production lost during downtime subsequent to Hurricane Ivan at Viosca Knoll Block 783 (Tahoe field) and lower production from fields in the Gulf of Mexico that were sold in June 2005. All Tahoe wells were back on production at the end of June 2005.
Continuing operations in Canada earned $78.6 million this quarter compared to $64.5 million a year ago. This increase was the result of higher crude oil and natural gas sales prices and higher crude oil sales volumes. Production and depreciation expenses increased due to more crude oil sales volumes for higher-cost heavy oil. Additionally, production expense for the Company’s synthetic oil operation increased due to higher repair and natural gas costs. Heavy oil prices did not increase in proportion to lighter oil prices in the 2005 period compared to 2004 due to a wider price differential between light and heavy oil in the 2005 period.
The Company sold most of its conventional oil and gas assets in Western Canada in the second quarter of 2004 for net cash proceeds of $582.7 million, which generated an after-tax gain in discontinued operations of $166.7 million. The operating results of those sold assets have been reported as discontinued operations for all 2004 periods presented.
U.K. operations earned $20.7 million in the current quarter, up from $15.8 million in the prior year. The improvement was primarily due to higher crude oil sales prices in the 2005 period compared to the 2004 quarter and were partially offset by lower oil sales volumes following the 2004 sale of the “T” Block field. Production expenses and depreciation expense declined in the most recent quarter due to lower sales volumes.
Operations in Ecuador earned $7.3 million in the second quarter of 2005 compared to $3.8 million a year ago. The increase was the result of higher sales prices and sales volumes in the 2005 period. Production expenses were slightly lower in the 2005 period due to the Company’s new transportation and marketing arrangements. Depreciation expense increased in the 2005 period due to higher sales volumes. The Company 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. Settlement negotiations are ongoing.
Operations in Malaysia reported earnings of $2.2 million in the 2005 period compared to income of $10.6 million during the same period in 2004. The decrease in Malaysia was primarily due to higher exploration expenses, a significant portion of which have no recorded tax benefit, which more than offset increased oil sales prices and volumes in the 2005 period versus the 2004 period.
Other international operations reported a loss of $6.8 million in the second quarter of 2005 compared to a loss of $2.6 million in the comparable period a year ago. Exploration expenses in the Republic of Congo were the primary cause of the higher loss in the 2005 period.
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Exploration and Production (Contd.)
On a worldwide basis, the Company’s crude oil and condensate prices averaged $43.10 per barrel in the second quarter 2005 compared to $34.14 in the 2004 period. Average crude oil and liquids production from continuing operations was a record 111,030 barrels per day in the second quarter of 2005 compared to 97,375 barrels per day in the second quarter of 2004, with the increase primarily attributable to production at the Front Runner field in the deepwater Gulf of Mexico, which commenced production in the fourth quarter of 2004, and higher heavy oil production at the Seal area in Western Canada. Crude oil sales volumes from continuing operations averaged 114,526 barrels per day in the second quarter 2005 compared to 99,819 barrels per day in the 2004 period. North American natural gas sales prices averaged $7.25 per thousand cubic feet (MCF) in the most recent quarter compared to $6.22 per MCF in the same quarter of 2004. Natural gas sales volumes from continuing operations averaged 107 million cubic feet a day in the second quarter 2005, down 16 million cubic feet per day from the 2004 quarter primarily due to production lost during downtime subsequent to Hurricane Ivan at Viosca Knoll Block 783 (Tahoe field) and lower production from fields in the Gulf of Mexico that were sold in June 2005.
Operations in the United States for the six months ended June 30, 2005 produced income of $249.8 million compared to income of $84.2 million in 2004. The improvement was primarily due to a $106.8 million after-tax gain on sale of oil and gas properties in the Gulf of Mexico, higher oil and natural gas sales prices and higher oil sales volumes due to the start-up of the Front Runner field in the deepwater Gulf of Mexico in the fourth quarter of 2004. Production expense increased due to higher oil sales volume and higher workover costs. Depreciation expense increased due to the higher crude oil sales volumes. Natural gas sales volumes declined due to lower sales volumes from Gulf of Mexico fields sold in June 2005 and production lost during downtime at the Tahoe field following Hurricane Ivan.
In the first half of 2005, Canadian continuing operations earned $134 million compared to $118.1 million a year ago. Higher sales prices for oil and natural gas were partially offset by lower natural gas sales volumes. Lower realized Canadian heavy oil prices in 2005 led to lower profits on heavy oil operations in the 2005 period. Production and depreciation expenses increased due to more crude oil sales volumes for higher-cost heavy oil. Additionally, production expenses for synthetic oil operations increased $5.1 million in the current period primarily due to higher repair and natural gas costs.
Income in the U.K. for the six-month period ended June 30, 2005 was $37.7 million compared to $29.6 million a year ago. The increase was due to higher sales prices of crude oil in the 2005 period, partially offset by lower sales volumes in the current period following the sale in 2004 of the “T” Block field. Production expenses and depreciation expense decreased due to the lower sales volumes.
For the first six months of 2005, earnings in Ecuador were $12.5 million compared to $6.7 million for the 2004 period. Higher crude oil sales prices and lower production expenses in the first half of 2005 were partially offset by higher depreciation expense. Production expenses were slightly lower in the 2005 period due to the Company’s new transportation and marketing arrangements effective in the second half of 2004.
Malaysia operations earned $11.9 million in the first half of 2005 compared to earnings of $6.6 million a year ago. The improvement in 2005 earnings was primarily due to higher crude oil sales volumes and prices, partially offset by increased dry hole and geological and geophysical expenses, the latter of which increased due to an extensive 3-D seismic program in the 2005 period.
Other international operations reported a loss of $31.1 million in the first six months of 2005 compared to a loss of $4.2 million in the 2004 period. The higher loss was primarily due to expensing two dry holes in the Republic of Congo in the 2005 period.
For the first six months of 2005, the Company’s sales price for crude oil and condensate averaged $41.55 per barrel compared to $32.58 per barrel in 2004. Crude oil and condensate production from continuing operations in the first half of 2005 averaged 109,892 barrels per day compared to 96,255 barrels per day a year ago. The increase was mostly attributable to higher production in the deepwater Gulf of Mexico at the Front Runner and Medusa fields and in Malaysia at the West Patricia field. The average sales price for North American natural gas in the first six months of 2005 was $6.98 per MCF, up from $6.05 in 2004. Natural gas sales volume from continuing operations were down from 124 million cubic feet per day in 2004 to 110 million cubic feet per day in 2005, with the decline due to lower sales volumes from Gulf of Mexico fields sold in June 2005 and production lost during downtime at the Tahoe field following Hurricane Ivan.
Additional details about results of oil and gas operations are presented in the tables on page 20.
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Selected operating statistics for the three-month and six-month periods ended June 30, 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 – Continuing operations
Crude oil and condensate – dollars per barrel (2)
Canada (3) – light
– heavy (4)
Malaysia (5)
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
Three Months Ended June 30, 2005
Oil and gas sales and other 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 June 30, 2004
Six Months Ended June 30, 2005
Six Months Ended June 30, 2004
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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 generated a profit of $59.7 million during the second quarter of 2005 compared to a profit of $27.4 million in the same period a year ago. The Company’s United States refining margin was significantly better in the current quarter compared to the same quarter of 2004. Earnings in the United Kingdom were $7.7 million in the second quarter of 2005, a decrease of $4.4 million compared to the same period a year ago, with the lower earnings in 2005 resulting from lower petroleum products sold and higher maintenance costs due to the Milford Haven refinery undergoing a full turnaround in the 2005 period. Worldwide petroleum product sales averaged 354,342 barrels per day in 2005, compared to 347,972 barrels per day in the same period in 2004. Worldwide refinery inputs were 176,218 barrels per day in the second quarter of 2005 compared to 181,700 in the 2004 quarter; inputs in 2005 were adversely affected by the Milford Haven refinery turnaround.
Refining and marketing operations in North America in the first half of 2005 had earnings of $51.4 million compared to income of $16.9 million in the 2004 period. United States refining margins improved significantly in the current period compared to a year ago. The 2004 period also included a net after-tax gain of $3 million from sale of the Company’s jointly owned terminals in the U.S. Results in the United Kingdom reflected earnings of $10.5 million in the six months ended June 30, 2005 compared to a profit of $16.2 million in 2004. The decrease was primarily due to lower volumes of petroleum products sold as a result of the Milford Haven refinery turnaround.
Refinery inputs – barrels per day
Petroleum products sold – barrels per day
Gasoline
Kerosine
Diesel and home heating oils
Residuals
Asphalt, LPG and other
LPG and other
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The net cost of corporate activities, which include interest income and expense and corporate overhead not allocated to operating functions, was $9.6 million in the current quarter compared to $11.2 million in the 2004 quarter as lower net interest expense and higher foreign exchange gains more than offset higher administrative costs in 2005. In the first six months of 2005, corporate activities reflected a net cost of $15.8 million compared to a net cost of $25.3 million a year ago. Lower net interest expenses and higher foreign exchange gains in 2005 were partially offset by higher administrative costs in the current period.
Financial Condition
Net cash provided by continuing operating activities was $452.4 million for the first six months of 2005 compared to $494.9 million for the same period in 2004. The decline in 2005 was primarily attributable to changes in other operating working capital. Changes in operating working capital other than cash and cash equivalents used cash of $102.5 million in the first six months of 2005 and $1.8 million in the first six months of 2004. This use of working capital in 2005 was primarily caused by an increase in accounts receivable that was partially offset by an increase in accounts payable. Cash from operating activities was reduced by expenditures for major repairs and asset retirement obligations totaling $27.8 million in the first six months of 2005 and $9 million in 2004, with the increase in 2005 mostly attributable to a full plant-wide turnaround at the Milford Haven, Wales refinery. Proceeds from the sale of assets, excluding discontinued operations, provided cash of $160.4 million in the first six months of 2004 compared to $40.7 million in the same period in 2004.
Other predominant uses of cash in each year were for dividends, which totaled $41.5 million in 2005 and $36.8 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 June 30, 2005 was $500.5 million, up $76.1 million from December 31, 2004. This level of working capital includes carrying certain inventories using lower historical costs under LIFO accounting. The carrying value of these inventories were $345 million and $219 million below current costs at June 30, 2005 and December 31, 2004, respectively.
At June 30, 2005, long-term notes payable of $597.8 million was virtually unchanged from December 31, 2004. Long-term nonrecourse debt of a subsidiary was $11.1 million, down $4.4 million from December 31, 2004, primarily due to repayments. A summary of capital employed at June 30, 2005 and December 31, 2004 follows.
Capital Employed
Total capital employed
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Financial Condition (Contd.)
On June 14, 2005, Murphy entered into a five year $1 billion committed credit facility, whereby the Company and certain wholly-owned subsidiaries may borrow funds from a major banking consortium. The new credit facility replaces two similar committed credit facilities with an aggregate borrowing capacity of $700 million. Borrowings under the new credit facility bear interest at prime or varying cost of fund options. Facility fees are due on the commitments. No amounts had been borrowed under this credit facility as of June 30, 2005.
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 viability of the project. The guidance in this FSP was applied beginning in April 2005 (see Note C to the consolidated financial statements). The adoption of this FSP did not have any effect on the Company’s net income.
In October 2004, the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (the “Act”) became law. 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 $2.4 million in the six-month period ended June 30, 2005 related to the Act.
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.
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
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Accounting and Other Matters (Contd.)
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 EITF 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.
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 June 30, 2005, the Company has a receivable of approximately $13.4 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.
Outlook
Crude oil and natural gas sales prices remain strong in July 2005. The Company expects its oil and natural gas production in the third quarter of 2005 to average 113,000 barrels of oil equivalent per day, down from 128,848 barrel equivalents per day in the second quarter. The anticipated decline is due to planned downtime for maintenance at U.K. fields and at Terra Nova, lost production during tropical storm shut-ins in the Gulf of Mexico, and no production from fields in the Gulf of Mexico that were sold in June 2005. North American refining and marketing margins have been weaker in the early part of the third quarter 2005 compared to average margins realized in the second quarter. The Company currently anticipates total capital expenditures in 2005 of approximately $1.3 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 June 30, 2005 for a remaining notional volume of 1.4 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 June 30, 2005, the estimated fair value of these
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (Contd.)
agreements was recorded as an asset of $6.1 million. A 10% increase in the average NYMEX price of natural gas would have increased this asset by $1.1 million, while a 10% decrease would have reduced the asset by a similar amount.
At June 30, 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 June 30, 2005, the estimated fair value of these agreements was recorded as a $28 million liability. A 10% increase in the price of Canadian heavy oil at the Hardisty terminal in Canada would have increased this liability by $7.5 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 half of 2005 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
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 2006. 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
25
PART II – OTHER INFORMATION (Contd.)
ITEM 1. LEGAL PROCEEDINGS (Contd.)
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 an insignificant effect on the Company’s net income and financial condition in the second quarter of 2005.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the annual meeting of security holders on May 11, 2005, the directors proposed by management were elected with a tabulation of votes to the nearest share as shown below. The tabulation of votes are presented prior to the two-for-one stock split effective June 3, 2005.
Frank W. Blue
George S. Dembroski
Claiborne P. Deming
Robert A. Hermes
R. Madison Murphy
William C. Nolan Jr.
Ivar B. Ramberg
Neal E. Schmale
David J. H. Smith
Caroline G. Theus
The amendment to increase the number of authorized shares of Common Stock from 200,000,000 to 450,000,000 was approved with 68,703,664 shares voted in favor, 12,780,678 shares voted in opposition and 77,665 shares not voted.
The earlier appointment by the Audit Committee of the Board of Directors of KPMG LLP as independent auditors for 2005 was approved with 80,819,629 shares voted in favor, 696,788 shares voted in opposition and 45,591 shares not voted.
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
27
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
August 5, 2005
(Date)
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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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