UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
For the quarterly period ended June 30, 2004
OR
For the transition period from to
Commission File Number 1-8590
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification Number)
200 Peach Street
P. O. Box 7000, El Dorado, Arkansas
(870) 862-6411
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No
Indicate by check mark whether the registrant is 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 June 30, 2004 was92,004,733.
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
Accounts receivable, less allowance for doubtful accounts of $11,272 in 2004 and $10,735 in 2003
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 $2,983,716 in 2004 and $3,472,133 in 2003
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, 2,608,646 shares of Common Stock in 2004 and 2,742,781 shares in 2003 at cost
Total stockholders’ equity
Total liabilities and stockholders’ equity
See Notes to Consolidated Financial Statements, page 5.
The Exhibit Index is on page 27.
1
CONSOLIDATED STATEMENTS OF INCOME (unaudited)
(Thousands of dollars except per share amounts)
Three Months Ended
June 30,
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, natural gas 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
Discontinued operations, net of tax
Income before cumulative effect of change in accounting principle
Cumulative effect of change in accounting principle, net of tax
NET INCOME
INCOME (LOSS) PER COMMON SHARE – BASIC
Discontinued operations
Cumulative effect of change in accounting principle
NET INCOME – BASIC
INCOME (LOSS) 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, net of tax
Cash flow hedges
Net derivative gains (losses)
Reclassification adjustments
Total cash flow hedges
Net gain (loss) from foreign currency translation
Minimum pension liability adjustment
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 retirement obligations
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
Other – net
Investing activities of discontinued operations:
Sales proceeds
Net cash provided (required) by investing activities
FINANCING ACTIVITIES
Increase (decrease) in notes payable
Decrease in nonrecourse debt of a subsidiary
Proceeds from exercise of stock options and employee stock purchase plans
Cash dividends paid
Net cash provided by (used in) financing activities
Effect of exchange rate changes on cash and cash equivalents
Net increase in cash and cash equivalents
Cash and cash equivalents at January 1
Cash and cash equivalents at June 30
SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid, net of refunds
Interest paid, net of amounts capitalized
4
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 4 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, 2003. 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, 2004, and the results of operations and cash flows for the three-month and six-month periods ended June 30, 2004 and 2003, in conformity with accounting principles generally accepted in the United States.
Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2003 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, 2004 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 of 2004 for total proceeds of $582.7 million. The sale of assets under one agreement occurred on April 22, 2004 and the other transaction was finalized on May 31, 2004. The Company recorded a gain of $166.7 million, net of $23.7 million in income taxes, upon sale of the properties. The Company expects to utilize the proceeds of the sales to fund operations in Malaysia and other areas and/or to repay debt under revolving credit agreements. The sale properties produced about 20,000 barrels of oil equivalent per day and had total reserves of approximately 46 million barrels equivalent from heavy oil, light oil, and natural gas properties. The operating results from the sale properties have been reported as discontinued operations beginning in the first quarter of 2004. Operating results for the three-month and six-month periods ended June 30, 2003 have been reclassified to conform to this presentation. These sale properties were formerly included in the Canadian exploration and production segment. The major assets (liabilities) associated with the sale properties were as follows:
Inventory
Prepaid expense
Property, plant and equipment, net of accumulated depreciation, depletion and amortization
Other noncurrent assets
Assets sold
Liabilities associated with assets sold
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 in 2004 periods
Income before income tax expense
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.
5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C – Employee and Retiree Pension and Postretirement Plans(Contd.)
Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.
The table that follows provides the components of net periodic benefit expense for the three-month and six-month periods ended June 30, 2004 and 2003.
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, 2003, that it expected to contribute $3.6 million to its domestic defined benefit pension plans and $4.6 million to its postretirement benefits plan during 2004. As of June 30, 2004, $.8 million and $1.1 million of contributions have been made to the domestic defined benefit pension plans and postretirement benefits plan, respectively. Murphy presently anticipates contributing during the last six months of 2004 an additional $5.9 million in the aggregate to fund its domestic plans. Murphy also anticipates contributing $1.5 million in the last six months of 2004 to fund its existing foreign defined benefit pension plans. Total anticipated funding in 2004 for the Company’s domestic and foreign defined benefits pension and postretirement benefits plans is $9.3 million.
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 in estimated benefits related to the Act in the first half of 2004. The Financial Accounting Standards Board has issued a FASB Staff Position that will require additional disclosures in future periods.
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.
6
Note D – Financial Instruments and Risk Management (Contd.)
7
prices provided Murphy with an average floor price of $3.24 per MMBTU and an average ceiling price of $4.64 per MMBTU. Murphy has a risk management control system to monitor natural gas price risk attributable both to forecasted natural gas sales prices and to Murphy’s hedging instruments. The control system involves using analytical techniques, including various correlations of natural gas sales prices to futures prices, to estimate the impact of changes in natural gas prices on Murphy’s cash flows from the sale of natural gas.
The fair values of the effective portions of the natural gas swaps, collars and puts and changes thereto are deferred in AOCI and are subsequently reclassified into Sales and Other Operating Revenues in the income statement in the periods in which the hedged natural gas sales affect earnings. For the six-month periods ended June 30, 2004 and 2003, Murphy’s earnings were not significantly affected by cash flow hedging ineffectiveness.
During the six-month period ended June 30, 2003, the Company paid $10.6 million for settlement of natural gas swap and collar agreements in the U.S. and Canada.
The fair value of the natural gas fuel swaps and the natural gas sales swaps and collars are both based on the average fixed price of the instruments and the published NYMEX and AECO “C” index futures price or natural gas price quotes from counterparties.
The fair values of the effective portions of the crude oil hedges and changes thereto were deferred in AOCI and subsequently reclassified into Sales and Other Operating Revenues in the income statement in the periods in which the hedged crude oil sales affected earnings. In the first six-months of 2003, cash flow hedging ineffectiveness relating to the crude oil sales swaps increased Murphy’s after-tax earnings by $1.4 million.
During the six-month period ended June 30, 2003 the Company paid $36.9 million for settlement of maturing crude oil swaps.
The fair value of the crude oil sales swaps are based on the average fixed price of the instruments and the published NYMEX index futures price or crude oil price quotes from counterparties.
During the next twelve months, the Company expects to reclassify approximately $5.6 million in net after-tax gains 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 – Asset Retirement Obligations
On January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed in service. When the liability is initially recorded, the Company will increase the carrying amount of the related long-lived asset by an amount equal to the
8
Note E – Asset Retirement Obligations (Contd.)
original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability is recognized as a gain or loss in the Company’s earnings.
The estimation of the future asset retirement obligation is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that will be required in future periods due to the availability of additional information, including prices for oil field services, technological changes, governmental requirements and other factors. Upon adoption of SFAS No. 143, the Company recorded a charge of $7 million, net of $1.4 million in income taxes, as the cumulative effect of a change in accounting principle. The noncash transition adjustment increased property, plant and equipment, accumulated depreciation, and asset retirement obligations by $142.9 million, $58.8 million, and $92.5 million, respectively.
The majority of the asset retirement obligation (ARO) recognized by the Company at June 30, 2004 relates to the estimated costs to dismantle and abandon its producing oil and gas properties and related equipment. A portion of the transition adjustment and ARO relates to its investment in retail gasoline stations. The Company did not record a retirement obligation for certain of its refining and marketing assets because sufficient information is presently not available to estimate a range of potential settlement dates for the obligation. In these cases, the obligation will be initially recognized in the period in which sufficient information exists to estimate the obligation.
A reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligations is shown in the following table.
Balance at January 1
Transition adjustment
Accretion expense
Liabilities incurred
Liabilities settled
Revisions of previous estimates
Changes due to translation of foreign currencies
Balance at June 30
Accretion expense of $1.2 million and $1.3 million shown in the above table were included in discontinued operating results for the six months ended June 30, 2004 and 2003, respectively. Liabilities settled in 2004 and 2003 included approximately $50.8 million and $54.9 million, respectively, in noncash reductions of asset retirement obligations associated with the sale of oil and gas properties.
Note F – 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, 2004 and 2003. The following table reconciles the weighted-average shares outstanding used for these computations.
Basic method
Dilutive stock options
Diluted method
The computation of earnings per share in the Consolidated Statements of Income did not consider outstanding options of 54,000 shares for the six-month period ended June 30, 2003 because the effects of these options would have been antidilutive. Average exercise prices of the options not used were $47.16 per share. There were no antidilutive options for the three-month periods ended June 30, 2004 and 2003 and the six-month period ended June 30, 2004.
9
Note F – Earnings per Share and Stock Options (Contd.)
The Company accounts for its stock options using 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. Under this method, compensation expense is not recorded for 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 Company would record compensation expense for any stock options deemed to be variable in nature. The Company accrues compensation expense for restricted stock awards and adjusts such costs for changes in the fair market value of Common Stock. SFAS No. 123, Accounting for Stock-Based Compensation, established accounting and disclosure requirements using a fair-value based method for stock-based employee compensation plans. As allowed by SFAS No. 123, the Company has elected to continue to apply the intrinsic-value based method prescribed by APB No. 25 and has adopted only the disclosure requirements of SFAS No. 123. Had the Company recorded compensation expense for stock options using SFAS No. 123, net income and earnings per share for the three-month and six-month periods ended June 30, 2004 and 2003 would be the pro forma amounts shown in the table below.
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
Note G – Accumulated Other Comprehensive Income
The components of Accumulated Other Comprehensive Income on the Consolidated Balance Sheets at June 30, 2004 and December 31, 2003 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 Instruments and Hedging Activities, decreased AOCI for the three months ended June 30, 2004 by $.4 million, net of $.2 million in income taxes, and hedging ineffectiveness increased net income by $.3 million, net of $.1 in income taxes. During the six-month period ended June 30, 2004, hedging activities decreased AOCI 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. Gains of $5.5 million, net of $2.9 million in taxes, were reclassified from AOCI to earnings in the six-month period ended June 30, 2004. During the three month period ended June 30, 2003, AOCI increased by $4.2 million, net of $2.4 million in income taxes, and hedging ineffectiveness increased net income by $.8 million, net of $.4 million in income taxes. During the first half of 2003, hedging activities increased AOCI by $3 million, net of $1.2 million in income taxes, and hedging ineffectiveness increased income by $1.4 million, net of $.9 million in income taxes. For the first half of 2003 losses of $27.1 million, net of $19.2 million in taxes, were reclassified from AOCI to earnings.
10
Note H – 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 82 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. If regulatory authorities require more costly alternatives than the proposed processes, future expenditures could exceed the accrued liability by up to an estimated $3 million.
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 minimus party as to ultimate responsibility at both 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 does not believe that the ultimate costs to clean-up the two Superfund sites will have a material adverse effect on its net income or cash flows 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 or cash flows.
Note I – 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 or 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. The Company believes that the counterclaim is without merit and that the amount of damages sought is frivolous. Trial will likely begin in January 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 financial condition.
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Note I – Other Contingencies (Contd.)
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. 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 financial condition.
On March 5, 2002, two of the Company’s subsidiaries filed suit against Enron Canada Corp. (Enron) to collect approximately $2.1 million owed to Murphy under canceled gas sales contracts. On May 1, 2002, Enron counterclaimed for approximately $19.8 million allegedly owed by Murphy under those same agreements. Although the lawsuit in the Court of Queen’s Bench, Alberta, is in its early stages and no assurance can be given about the outcome, the Company does not believe that the Enron counterclaim is meritorious and does not believe that the ultimate resolution of this matter will have a material adverse effect on its financial condition.
Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business and none of which is expected to have a material adverse effect on the Company’s financial condition. 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 earnings or financial condition 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, 2004, the Company had contingent liabilities of $9 million under a financial guarantee and $42.6 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.
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Note J – Business Segments
June 30, 2004
June 30, 2003
(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
13
Note K – Accounting Matters
In July 2003 the FASB undertook to review whether mineral interests in properties (mineral leases) held by oil and gas companies should be recorded and disclosed as intangible assets under the guidance of SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. The FASB is considering whether an oil and gas company’s investment in mineral leases should be classified as intangible assets. SFAS No. 141 and SFAS No. 142 established new accounting guidelines for both finite lived intangible assets and indefinite lived intangible assets. Under SFAS No. 141 and SFAS No. 142, intangible assets should be separately reported on the Balance Sheet, with accompanying disclosures in the notes to the financial statements. SFAS No. 142 does not change the accounting prescribed in SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, and is silent about whether its disclosure provisions apply to oil and gas companies. The Company does not believe that SFAS No. 141 and SFAS No. 142 change the classification and disclosure of oil and gas mineral leases and it continues to classify these assets as part of Property, Plant and Equipment in the Consolidated Balance Sheet and does not provide the additional disclosures for these assets. The FASB has issued a proposed staff position stating that drilling and mineral rights of oil and gas producing entities that are within the scope of SFAS 19 are not subject to the intangible asset classification and disclosure rules of SFAS No. 142. Should the FASB proposed staff position not be adopted and it is determined that oil and gas mineral leases are intangible assets in accordance with SFAS No. 141 and SFAS No. 142, the Company would reclassify $112 million and $143 million as intangible undeveloped mineral interests at June 30, 2004 and December 31, 2003, respectively. In addition, a reclassification of $5 million and $8 million would be made as intangible developed mineral interests at June 30, 2004 and December 31, 2003, respectively. Both intangible assets would be presented net of accumulated amortization. Historically, undeveloped mineral leases have been amortized over the life of the lease period, while developed mineral leases have been amortized using the units of production method over the expected life of proved reserves. The amounts included herein are based on our understanding of the issue on the EITF’s agenda. If all mineral leases associated with oil and gas properties are deemed to be intangible assets in accordance with SFAS No. 141 and SFAS No. 142 by the EITF:
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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 2004 was a record $349.9 million, $3.75 per diluted share, compared to net income of $79.7 million, $.86 per diluted share, in the second quarter of 2003. Net income in the current period included income from discontinued operations of $181.8 million, $1.95 per share, $166.7 million of which was a net gain on sale of most conventional oil and gas assets in Western Canada. Discontinued operations income in the second quarter of 2003 was $7.4 million, $.08 per share. Income from continuing operations in the second quarter of 2004 was also a record $168.1 million, $1.80 per share, compared to $72.3 million, $.78 per share, in the same period in 2003.
In the current quarter, the Company’s exploration and production operations earned $139.8 million, an increase of $59.5 million from $80.3 million earned in the 2003 period. The earnings improvement in 2004 was primarily caused by higher oil and gas sales prices and sales volumes. The 2003 period included a $34 million after-tax gain on sale of North Sea properties. The Company’s refining and marketing operations generated income of $39.5 million in the second quarter of 2004 compared to income of $.3 million for the three months ended June 30, 2003. The improvement was due to significantly better margins in North America and the United Kingdom in the current quarter. A fire that destroyed the ROSE unit at the Meraux, Louisiana refinery in June 2003 lowered earnings in the second quarter of 2003 by $12.3 million. The after-tax costs of the corporate function were $11.2 million in the 2004 second quarter compared to $8.3 million in the 2003 quarter. Higher administrative expenses were the primary reasons for increased costs in 2004.
For the first six months of 2004, net income totaled $448.1 million, $4.81 per diluted share, compared to $166.8 million, $1.80 per diluted share, for the first half of 2003. Income from discontinued operations was $199.3 million, $2.14 per share in the first half of 2004, while the same period in 2003 totaled $18.6 million, $.20 per share. Continuing operations earned $248.8 million, $2.67 per share, in 2004 and $155.2 million, $1.68 per share, in 2003. Additionally in 2003, upon adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, effective January 1, 2003, the Company recorded in the income statement an after-tax charge of $7 million, $.08 per share, as the cumulative effect of a change in accounting principle.
Exploration and production earnings in the first six months of 2004 were up $85 million from the prior year, mainly due to higher oil and natural gas sales prices and sales volumes in the 2004 period, partially offset by lower gains on sale of assets and higher exploration expenses. The Company’s refining and marketing operations generated a profit of $33.1 million in the first half of 2004, but incurred a loss of $3.2 million in the 2003 period. The improved current year result was based on strong margins in both the North American and U.K. businesses in the second quarter of 2004 coupled with $12.3 million of after-tax costs in the 2003 period resulting from a fire at the Meraux refinery. Corporate after-tax costs were $25.3 million in the first six months of 2004 compared to a profit of $2.4 million in the 2003 period. The prior year included a benefit on U.S. tax settlements of $20.1 million. Higher net interest and administrative expenses were also components of the higher costs in the 2004 period.
Exploration and Production
Results of continuing exploration and production operations are presented by geographic segment below.
Three Months
Ended June 30,
Six Months
Exploration and production
Other International
Exploration and production operations in the United States reported earnings of $47.7 million in the second quarter of 2004 compared to earnings of $2.8 million a year ago. This improvement was primarily due to higher oil and natural gas sales prices coupled with higher sales volumes due to the start-up, in the fourth quarter of 2003, of the Medusa and Habanero fields in deepwater Gulf of Mexico. Production expenses and depreciation expense increased due to the higher crude oil and natural gas sales volumes. Exploration expenses were $10.3 million lower in the 2004 period compared to 2003 primarily due to less dry holes expense.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (Contd.)
Exploration and Production (Contd.)
Continuing operations in Canada earned $64.5 million this quarter compared to $35.1 million a year ago. This increase was the result of higher crude oil and natural gas sales prices and higher crude oil sales volumes, but was partially offset by lower natural gas production volumes. Production expenses associated with synthetic crude oil volumes increased $2.9 million in the current period due to higher natural gas costs and increased repairs.
The Company completed the sale of 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 also been reported as discontinued operations for all periods presented.
U.K. operations earned $15.8 million in the current quarter, down from $47.4 million from the prior year. The 2003 period included a $34 million after-tax gain on sale of the Ninian and Columba fields. Higher crude oil sales prices in 2004 more than offset earnings in the 2003 period from the Ninian and Columba fields, which were sold in May 2003.
Operations in Ecuador earned $3.8 million in the second quarter of 2004 compared to $.8 million a year ago. The improvement was the result of higher sales prices and sales volumes in the 2004 period. Higher sales volumes were attributable to start-up of a new third-party owned heavy oil pipeline in late 2003. Production expenses and depreciation expense increased in the 2004 period due to higher sales volumes. Income tax expense was $1.9 million in 2004, but there was no income tax expense in 2003.
Operations in Malaysia reported earnings of $10.6 million in the 2004 period compared to a loss of $5.3 million during the same period in 2003. The improvement in Malaysia was primarily due to crude oil sales from the West Patricia field partially offset by increased dry hole expenses. There were no crude oil sales at the West Patricia field during the 2003 period.
Other international operations reported a loss of $2.6 million in the second quarter of 2004 compared to a loss of $.5 million in the comparable period a year ago. Lower revenues from natural gas storage facilities and higher geological and geophysical costs in the Congo were the primary causes of the higher loss in the 2004 period.
Operations in the United States for the six months ended June 30, 2004 produced income of $84.2 million compared to income of $15.6 million in 2003. The improvement was primarily due to higher oil and natural gas sales prices and sales volumes, partially offset by higher dry hole expenses. The higher sales volumes are the result of the start-up in the last quarter of 2003 of the Medusa and Habanero fields in deepwater Gulf of Mexico. Also contributing to the improved results in 2004 were $15.4 million in after-tax gains on disposal of several minor natural gas properties onshore United States.
In the first half of 2004, Canadian continuing operations earned $118.1 million compared to $79.8 million a year ago. Higher sales prices for oil and natural gas and higher sales volumes of crude oil were partially offset by lower natural gas sales volumes. Production expenses for synthetic oil operations increased $8.2 million in the current period primarily due to higher repairs and natural gas costs.
Income in the U.K. for the six-month period ended June 30, 2004 was $29.6 million compared to $66.5 million a year ago. The decrease was due to the $34 million after-tax gain on sale of Ninian and Columba in 2003 and lower sales volumes of crude oil in the 2004 period, partially offset by higher sales prices in the latter period.
For the first six months of 2004, earnings in Ecuador were $6.7 million compared to $6.3 million for the 2003 period. Higher crude oil sales volumes in the first half of 2004 were mostly offset by higher production, depreciation and income tax expenses.
Malaysia operations earned $6.6 million in the first half of 2004 compared to a loss of $10.8 million a year ago. The improvement in 2004 earnings was primarily due to crude oil sales from the West Patricia field partially offset by increased dry hole expenses. No crude oil sales occurred at the West Patricia field during the 2003 period.
Other international operations reported a loss of $4.2 million in the first six months of 2004 compared to a loss of $1.4 million in the 2003 period. Lower gas storage revenue and higher exploration expenses and administrative costs were the primary causes of the increased loss.
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On a worldwide basis, the Company’s crude oil and condensate prices averaged $34.14 per barrel in the second quarter 2004 compared to $24.60 in the 2003 period. Average crude oil and liquids production from continuing operations was 97,375 barrels per day compared to 75,624 barrels per day in the second quarter of 2003, with the increase primarily attributable to production at the Medusa and Habanero fields in deepwater Gulf of Mexico, both of which commenced production in the fourth quarter of 2003, and higher volumes at the West Patricia field in Malaysia due to a full quarter of production in 2004. Production at the West Patricia field commenced in May 2003. Oil sales volumes from continuing operations averaged 99,819 barrels per day in the second quarter 2004 compared to 67,452 barrels per day in the 2003 period. North American natural gas sales prices averaged $6.22 per MCF in the second quarter 2004 compared to $5.22 per MCF in the same quarter of 2003. Total natural gas sales volumes from continuing operations averaged 123 million cubic feet a day in the second quarter 2004, up 11 million cubic feet per day from the 2003 quarter primarily due to production from the Medusa and Habanero fields in the deepwater Gulf of Mexico. The Company hedged the sales prices of a portion of its oil and natural gas production in 2003. In the second quarter of 2003, these hedges reduced the average realized worldwide crude oil and North American natural gas sales prices by $1.54 per barrel and $.22 per MCF, respectively.
For the first six months of 2004, the Company’s sales price for crude oil and condensate averaged $32.58 per barrel compared to $26.28 per barrel in 2003. Crude oil and condensate production from continuing operations in the first half of 2004 averaged 96,255 barrels per day compared to 71,722 barrels per day a year ago. The increase was mostly attributable to start-up of Medusa and Habanero in late 2003 and a full six months production from the West Patricia field in shallow-water Malaysia. Average sales prices for North American natural gas in the first six months of 2004 was $6.05 per MCF, up from $5.58 in 2003. Total natural gas sales volume from continuing operations increased by 9% and averaged 124 million cubic feet per day in the 2004 period, with the increase resulting from production at the Medusa and Habanero fields in the deepwater Gulf of Mexico. The Company’s 2003 hedging program reduced the average realized worldwide crude oil and North American natural gas sales prices in the first six months of 2003 by $2.39 per barrel and $.35 per MCF, respectively.
The tables on pages 18 and 19 provide additional details of the results of exploration and production operations for the second quarter and first six months of 2004 and 2003.
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Selected operating statistics for the three-month and six-month periods ended June 30, 2004 and 2003 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)
United States (4)
Canada (3) – light
– heavy (4)
– offshore (4)
– synthetic (4)
Natural gas – dollars per thousand cubic feet
United States (2) (4)
Canada (3) (4)
United Kingdom (3)
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CONTINUING OIL AND GAS OPERATING RESULTS (unaudited)
United
States
UnitedKing-
dom
SyntheticOil –
Three Months Ended June 30, 2004
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, 2003
Six Months Ended June 30, 2004
Six Months Ended June 30, 2003
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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 $27.4 million during the second quarter of 2004 compared to a loss of $1.5 million in the same period a year ago. The 2003 period included $12.3 million in after-tax costs relating to a fire at the Company’s Meraux, Louisiana refinery. The Company’s North American refining and marketing margins were significantly higher in the current quarter compared to margins in the same quarter of 2003. Earnings in the United Kingdom were $12.1 million in the second quarter of 2004, an increase of $10.3 million over the same period a year ago, with the higher earnings in 2004 resulting from significantly improved margins. Worldwide petroleum product sales averaged 347,972 barrels per day in 2004, a 27% increase from the second quarter of 2003. Worldwide refinery inputs were 181,700 barrels per day in the second quarter of 2004 compared to 137,749 in the 2003 quarter; inputs in 2003 were adversely affected by the Meraux refinery fire.
Refining and marketing operations in North America in the first half of 2004 had earnings of $16.9 million compared to a loss of $7.9 million in the 2003 period, which included the net after-tax costs associated with the Meraux refinery fire. North American refining and marketing 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 $16.2 million in the six months ended June 30, 2004 compared to a profit of $4.7 million in 2003 due to higher margins compared to the same period a year ago.
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 $11.2 million in the current quarter compared to $8.3 million in the 2003 quarter. In the first six months of 2004, corporate activities reflected a net cost of $25.3 million compared to a net profit of $2.4 million a year ago. The six-month 2003 results included a $20.1 million gain from resolution of prior years’ tax matters. Excluding the tax resolution benefit, higher costs in the second quarter and first six months of 2004 compared to the comparable 2003 periods were attributable to higher administrative expenses and a lower portion of interest costs being capitalized, partially offset by more interest income earned on higher cash balances.
Financial Condition
Net cash provided by continuing operating activities was $494.9 million for the first six months of 2004 compared to $249.2 million for the same period in 2003. The improvement in 2004 was attributable to an increase in revenues due to higher oil, natural gas and product prices that exceeded the increase in cash costs for products sold and operating and administrative expenses. Changes in operating working capital other than cash and cash equivalents used cash of $1.8 million in the first six months of 2004 but provided cash of $6.1 million in the first six months of 2003. Cash from operating activities was reduced by expenditures for major repairs and asset retirement obligations totaling $9 million in 2004 and $26.2 million in 2003. Proceeds from the sale of assets, excluding discontinued operations, provided cash of $40.7 million in the first six months of 2004 compared to $69 million in the same period in 2003.
Other predominant uses of cash in each year were for dividends, which totaled $36.8 million in 2004 and $36.7 million in 2003 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 at June 30, 2004 was $876.2 million, up $647.7 million from December 31, 2003, with the increase primarily due to the proceeds from sales of most Western Canadian conventional oil and natural gas assets in the second quarter 2004. This level of working capital does not fully reflect the Company’s liquidity position, because the lower historical costs assigned to inventories under LIFO accounting were $205.4 million below current costs at June 30, 2004.
At June 30, 2004, long-term notes payable of $1,032.8 million were down $28.6 million from December 31, 2003 due to payments of amounts drawn under the Company’s long-term revolving credit agreements. Long-term nonrecourse debt of a subsidiary was $14 million, down $14.9 million from December 31, 2003, primarily due to repayments. A summary of capital employed at June 30, 2004 and December 31, 2003 follows.
Capital Employed
Total capital employed
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Accounting and Other Matters (Contd.)
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 arbiters 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, 2004, the Company has a receivable of approximately $10.2 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 financial position.
Outlook
Crude oil and natural gas sales prices have remained strong during July 2004. Production is expected to average approximately 114,000 barrels of oil equivalent per day in the third quarter 2004. The Front Runner field, in the deepwater Gulf of Mexico, is expected to start up production in the fourth quarter 2004. In April, the Company’s Board of Directors approved a development plan for the Kikeh field in deepwater Block K, Malaysia. PETRONAS and the Company’s 20% partner, PETRONAS Carigali, must also approve the Kikeh development plan. The development plan calls for first production in late 2007. North American gasoline marketing margins have weakened early in the third quarter 2004 compared to the just completed second quarter. The Company currently anticipates total capital expenditures in 2004 of approximately $950 million.
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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.
The Company was a party to interest rate swaps at June 30, 2004 with notional amounts totaling $30 million that were designed to hedge fluctuations in cash flows of a similar amount of variable-rate debt. These swaps mature in July and October 2004. The swaps require the Company to pay an average interest rate of 6.06% over their composite lives, and at June 30, 2004, the interest rate to be received by the Company averaged 1.16%. The variable interest rate received by the Company under each swap contract is repriced quarterly. The Company considers these swaps to be a hedge against potentially higher future interest rates. The estimated fair value of these interest rate swaps was recorded as a liability of $.5 million at June 30, 2004, with the offsetting loss recorded in Accumulated Other Comprehensive Income (AOCI) in Stockholders’ Equity.
At June 30, 2004, 39% of the Company’s debt had variable interest rates. Based on debt outstanding at June 30, 2004, a 10% increase in variable interest rates would increase the Company’s interest expense approximately $1.4 million for the next 12 months after including the favorable effect resulting from lower net settlement payments under the aforementioned interest rate swaps.
Murphy was a party to natural gas price swap agreements at June 30, 2004 for a remaining notional volume of 5.7 million MMBTU that are intended to hedge the financial exposure of its Meraux, Louisiana and Superior, Wisconsin refineries to fluctuations in the future price of a portion of natural gas to be purchased for fuel from July 1, 2004 through 2006. In each month of settlement, the swaps require Murphy to pay an average natural gas price of $2.78 per MMBTU and to receive the average NYMEX price for the final three trading days of the month. At June 30, 2004, the estimated fair value of these agreements was recorded as an asset of $18.4 million. A 10% increase in the average NYMEX price of natural gas would have increased this asset by $3.4 million, while a 10% decrease would have reduced the asset by a similar amount. Additionally, the Company was a party to natural gas price swap agreements at June 30, 2004 for a total remaining notional volume of 2.4 million MMBTU that effectively fixed the settlement price for the natural gas purchase swaps maturing in July through October 2004. The terms are nearly identical to the aforementioned swaps and require Murphy to pay the average NYMEX price for the final three trading days of the month and receive an average natural gas price of $5.235 per MMBTU. At June 30, 2004 the estimated fair value of these agreements was recorded as a liability of $2.4 million. A 10% increase in the average NYMEX index price of natural gas would have increased this liability by $1.5 million, while a 10% decrease would have reduced this liability by a similar amount.
At June 30, 2004, the Company was a party to natural gas put options covering 3.1 million MMBTU in future natural gas sales during July through October, 2004. The options are intended to hedge the financial exposure of the Company’s natural gas sales in the U.S. should the future selling price during the contract period fall below a $4.00 per MMBTU floor price. At June 30, 2004, the estimated fair value of these agreements was recorded as an asset valued at less than $.1 million. A 10% change in the price of natural gas would not have a significant impact on the fair value of this asset.
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ITEM 4. CONTROLS AND PROCEDURES
The Company, under the direction of its principal executive officer and principal financial officer, has established controls and procedures 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 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 second quarter of 2004 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting.
PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business and none of which is expected to have a material adverse effect on the Company’s financial condition. Based on information currently available to the Company, the ultimate resolution of matters referred to in this item is not expected to have a material adverse effect on the Company’s earnings or financial condition in a future period.
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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the annual meeting of security holders on May 12, 2004, the directors proposed by management were elected with a tabulation of votes to the nearest share as shown below.
Frank W. Blue
George S. Dembroski
Claiborne P. Deming
Robert A. Hermes
R. Madison Murphy
William C. Nolan Jr.
Ivar B. Ramberg
David J. H. Smith
Caroline G. Theus
The earlier appointment by the Audit Committee of the Board of Directors of KPMG LLP as independent auditors for 2004 was approved, with 83,766,707 shares voted in favor, 1,495,931 shares voted in opposition and 17,102 shares not voted.
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)
By
/s/ JOHN W. ECKART
John W. Eckart, Controller
(Chief Accounting Officer and Duly
Authorized Officer)
August 5, 2004
(Date)
26
EXHIBIT INDEX
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
Exhibits other than those listed above have been omitted since they are either not required or not applicable.
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