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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
FORM 10-Q
 
(Mark one)
x
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended June 30, 2002
 
OR
 
¨
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from                           to                                 
 
Commission File Number 1-8590
 
 
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)
 
Delaware
(State or other jurisdiction of
incorporation or organization)
  
71-0361522
(I.R.S. Employer
Identification Number)
 
200 Peach Street
P. O. Box 7000, El Dorado, Arkansas
(Address of principal executive offices)
  
71731-7000
(Zip Code)
 
(870) 862-6411
(Registrant’s telephone number, including area code)
 
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  þ  Yes  ¨  No
 
Number of shares of Common Stock, $1.00 par value, outstanding at June 30, 2002, was 45,816,063.
 

PART I—FINANCIAL INFORMATION
 
ITEM 1.    FINANCIAL STATEMENTS
 
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
 
    
(Unaudited)
         
    
June 30,
2002
     
December 31,
2001
  
ASSETS
                
Current Assets
                
Cash and cash equivalents
   
$
140,986
 
   
82,652
 
Accounts receivable, less allowance for doubtful accounts of $11,487 in 2002 and $11,263 in 2001
   
 
383,660
 
   
262,022
 
Inventories
                
Crude oil and blend stocks
   
 
96,923
 
   
38,917
 
Finished products
   
 
100,466
 
   
85,133
 
Materials and supplies
   
 
60,061
 
   
49,098
 
Prepaid expenses
   
 
76,443
 
   
61,062
 
Deferred income taxes
   
 
20,466
 
   
19,777
 
    
  
Total current assets
   
 
879,005
 
   
598,661
 
Property, plant and equipment, at cost less accumulated depreciation and amortization of $3,425,548 in 2002 and $3,277,673 in 2001
   
 
2,754,150
 
   
2,525,807
 
Goodwill, net
   
 
52,908
 
   
50,412
 
Deferred charges and other assets
   
 
92,493
 
   
84,219
 
    
  
Total assets
   
$
3,778,556
 
   
3,259,099
 
    
  
LIABILITIES AND STOCKHOLDERS’ EQUITY
                
Current liabilities
                
Current maturities of long-term debt
   
$
50,441
 
   
48,250
 
Accounts payable and accrued liabilities
   
 
584,799
 
   
463,429
 
Income taxes
   
 
52,656
 
   
48,378
 
    
  
Total current liabilities
   
 
687,896
 
   
560,057
 
Notes payable
   
 
712,845
 
   
416,061
 
Nonrecourse debt of a subsidiary
   
 
92,456
 
   
104,724
 
Deferred income taxes
   
 
329,432
 
   
302,868
 
Accrued dismantlement costs
   
 
169,569
 
   
160,764
 
Accrued major repair costs
   
 
46,416
 
   
44,570
 
Deferred credits and other liabilities
   
 
168,504
 
   
171,892
 
Stockholders’ equity
                
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued
   
 
—  
 
   
—  
 
Common stock, par $1.00, authorized 200,000,000 shares, issued 48,775,314 shares
   
 
48,775
 
   
48,775
 
Capital in excess of par value
   
 
547,098
 
   
527,126
 
Retained earnings
   
 
1,078,797
 
   
1,096,567
 
Accumulated other comprehensive loss
   
 
(25,649
)
   
(83,309
)
Unamortized restricted stock awards
   
 
(231
)
   
(968
)
Treasury stock, 2,959,251 shares of Common Stock in 2002, 3,444,234 shares in 2001, at cost
   
 
(77,352
)
   
(90,028
)
    
  
Total stockholders’ equity
   
 
1,571,438
 
   
1,498,163
 
    
  
Total liabilities and stockholders’ equity
   
$
3,778,556
 
   
3,259,099
 
    
  
 
See Notes to Consolidated Financial Statements, page 5.
 
The Exhibit Index is on page 20.

1

 
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF INCOME (unaudited)
(Thousands of dollars, except per share amounts)
 
    
Three Months Ended
June 30,
     
Six Months Ended
June 30,
  
    
2002
     
2001
     
2002
     
2001
  
REVENUES
                              
Crude oil and natural gas sales
   
$
259,873
 
   
232,952
 
   
454,806
 
   
470,151
 
Petroleum product sales
   
 
734,680
 
   
778,071
 
   
1,258,410
 
   
1,450,302
 
Crude oil trading sales
   
 
90,889
 
   
157,866
 
   
154,109
 
   
396,326
 
Other operating revenues
   
 
48,276
 
   
128,145
 
   
95,293
 
   
165,950
 
Interest and other nonoperating revenues
   
 
999
 
   
3,345
 
   
2,002
 
   
7,035
 
    
  
  
  
Total revenues
   
 
1,134,717
 
   
1,300,379
 
   
1,964,620
 
   
2,489,764
 
    
  
  
  
COSTS AND EXPENSES
                              
Crude oil, products and related operating expenses
   
 
914,394
 
   
922,413
 
   
1,600,476
 
   
1,835,624
 
Exploration expenses, including undeveloped lease amortization
   
 
61,767
 
   
41,589
 
   
103,788
 
   
79,550
 
Selling and general expenses
   
 
23,129
 
   
24,983
 
   
45,491
 
   
46,029
 
Depreciation, depletion and amortization
   
 
84,682
 
   
58,256
 
   
155,371
 
   
112,488
 
Amortization of goodwill
   
 
—  
 
   
785
 
   
—  
 
   
1,573
 
Interest expense
   
 
13,287
 
   
9,702
 
   
22,829
 
   
19,446
 
Interest capitalized
   
 
(4,607
)
   
(4,333
)
   
(9,424
)
   
(7,919
)
    
  
  
  
Total costs and expenses
   
 
1,092,652
 
   
1,053,395
 
   
1,918,531
 
   
2,086,791
 
    
  
  
  
Income before income taxes
   
 
42,065
 
   
246,984
 
   
46,089
 
   
402,973
 
Income tax expense
   
 
28,136
 
   
84,416
 
   
29,626
 
   
142,569
 
    
  
  
  
NET INCOME
   
$
13,929
 
   
162,568
 
   
16,463
 
   
260,404
 
    
  
  
  
NET INCOME PER COMMON SHARE
                              
Basic
   
$
.30
 
   
3.60
 
   
.36
 
   
5.77
 
Diluted
   
$
.30
 
   
3.56
 
   
.36
 
   
5.72
 
Average Common shares outstanding
                              
Basic
   
 
45,784,073
 
   
45,206,604
 
   
45,635,493
 
   
45,139,453
 
Diluted
   
 
46,133,432
 
   
45,644,457
 
   
46,029,510
 
   
45,490,094
 
 
See Notes to Consolidated Financial Statements, page 5.

2

 
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)
(Thousands of dollars)
 
    
Three Months Ended June 30,
     
Six Months Ended
June 30,
  
    
2002
   
2001
     
2002
     
2001
  
Net income
   
$
13,929
   
162,568
 
   
16,463
 
   
260,404
 
Other comprehensive income (loss), net of tax
                            
Cash flow hedges
                            
Net derivative gains
   
 
4,675
   
1,454
 
   
7,622
 
   
2,053
 
Reclassification adjustments
   
 
945
   
(232
)
   
(2,378
)
   
1,346
 
    
  
  
  
Total cash flow hedges
   
 
5,620
   
1,222
 
   
5,244
 
   
3,399
 
Net gain (loss) from foreign currency translation
   
 
57,412
   
29,571
 
   
52,416
 
   
(21,868
)
    
  
  
  
Other comprehensive income (loss) before cumulative effect of accounting change
   
 
63,032
   
30,793
 
   
57,660
 
   
(18,469
)
Cumulative effect of accounting change (Note B)
   
 
—  
   
—  
 
   
—  
 
   
6,642
 
    
  
  
  
Other comprehensive income (loss)
   
 
63,032
   
30,793
 
   
57,660
 
   
(11,827
)
    
  
  
  
COMPREHENSIVE INCOME
   
$
76,961
   
193,361
 
   
74,123
 
   
248,577
 
    
  
  
  
 
See Notes to Consolidated Financial Statements, page 5.
 

3

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(Thousands of dollars)
 
    
Six Months Ended
June 30,
  
    
2002
     
2001
  
OPERATING ACTIVITIES
                
Net income
   
$
16,463
 
   
260,404
 
Adjustments to reconcile net income to net cash provided by operating activities
                
Depreciation, depletion and amortization
   
 
155,371
 
   
112,488
 
Provisions for major repairs
   
 
9,332
 
   
11,051
 
Expenditures for major repairs
   
 
(9,805
)
   
(9,861
)
Dry holes
   
 
72,844
 
   
46,572
 
Amortization of undeveloped leases
   
 
12,267
 
   
10,852
 
Amortization of goodwill
   
 
—  
 
   
1,573
 
Deferred and noncurrent income tax charges
   
 
11,215
 
   
41,491
 
Pretax gains from disposition of assets
   
 
(5,700
)
   
(95,246
)
Net increase in operating working capital other than cash and cash equivalents
   
 
(96,364
)
   
(35,852
)
Other operating activities—net
   
 
5,349
 
   
8,447
 
    
  
Net cash provided by operating activities
   
 
170,972
 
   
351,919
 
    
  
INVESTING ACTIVITIES
                
Property additions and dry holes
   
 
(416,239
)
   
(393,823
)
Proceeds from sale of assets
   
 
28,648
 
   
159,079
 
Other investing activities—net
   
 
2
 
   
(258
)
    
  
Net cash required by investing activities
   
 
(387,589
)
   
(235,002
)
    
  
FINANCING ACTIVITIES
                
Increase (decrease) in notes payable
   
 
298,112
 
   
(9,714
)
Decrease in nonrecourse debt of a subsidiary
   
 
(13,629
)
   
(7,201
)
Cash dividend paid
   
 
(34,233
)
   
(33,835
)
Proceeds from exercise of stock options and employee stock purchase plan
   
 
23,024
 
   
14,333
 
Other financing activities—net
   
 
(2,526
)
   
(2,000
)
    
  
Net cash provided (required) by financing activities
   
 
270,748
 
   
(38,417
)
    
  
Effect of exchange rate changes on cash and cash equivalents
   
 
4,203
 
   
(5,234
)
    
  
Net increase in cash and cash equivalents
   
 
58,334
 
   
73,266
 
Cash and cash equivalents at January 1
   
 
82,652
 
   
132,701
 
    
  
Cash and cash equivalents at June 30
   
$
140,986
 
   
205,967
 
    
  
SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
                
Cash income taxes paid
   
$
10,916
 
   
79,828
 
Interest paid, net of amounts capitalized
   
 
9,082
 
   
7,908
 
 
See Notes to Consolidated Financial Statements, page 5.
 

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, 2001. 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, and the results of its operations and cash flows for such periods, in conformity with accounting principles generally accepted in the United States of America.
 
Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2001 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, 2002 are not necessarily indicative of future results.
 
Note B—New Accounting Principles
 
Effective January 1, 2002, the Company was required to adopt Statement of Financial Accounting Standards (SFAS) No. 142, Goodwill and Other Intangible Assets, which requires that amortization of goodwill be replaced with annual tests for impairment and that intangible assets other than goodwill be amortized over their useful lives. Murphy assesses the recoverability of goodwill by comparing the fair value of net assets for conventional oil and natural gas operations in Canada with the carrying value of these net assets, including goodwill. The fair value of the conventional oil and natural gas reporting unit is determined using the expected present value of future cash flows. The carrying amount of goodwill at June 30, 2002 was $52.9 million. The change in the carrying amount of goodwill for the period ended June 30, 2002 was due to a change in the exchange rate of Canadian dollars and U.S. dollars. Goodwill is tested for impairment at the end of the Company’s fiscal year after the oil and gas reserve information is available. Based on its assessment of the fair value of its Canadian conventional oil and natural gas operations, the Company believes the recorded value of goodwill is not impaired. Adjusted net income for the six-month period ended June 30, 2001, excluding goodwill amortization of $1.6 million ($.03 basic and diluted earnings per share), was $262 million. Adjusted basic and diluted earnings per share for the six-month period ended June 30, 2001 were $5.80 and $5.76, respectively.
 
Also effective January 1, 2002, Murphy was required to adopt SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which supercedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of and the accounting and reporting provisions of APB Opinion No. 30, Reporting the Results of Operations-Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual, and Infrequently Occurring Events and Transactions. There was no effect of adopting SFAS No. 144 on the Company’s consolidated financial statements.
 
In July 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations, which will require the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability must be 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 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. Upon adoption of SFAS No. 143 on January 1, 2003, the Company will recognize transition adjustments for existing asset retirement obligations, long-lived assets and accumulated depreciation, all net of related income tax effects, as the cumulative effect of a change in accounting principle. After adoption, any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability will be recognized as a gain or loss in the Company’s earnings. At this time, it is not practicable to reasonably estimate the impact of adopting SFAS No. 143 on the Company’s consolidated financial statements.

5

 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
 
Note B—New Accounting Principles (Contd.)
 
Effective January 1, 2001, Murphy adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138 (SFAS Nos. 133/138). As a result of the change, Murphy records the fair values of its derivative instruments as either assets or liabilities. All such instruments have been designated as hedges of forecasted cash flow exposures. Changes in the fair value of a qualifying cash flow hedging derivative are deferred and recorded as a component of Accumulated Other Comprehensive Loss (AOCL) in the Consolidated Balance Sheet until the forecasted transaction occurs, at which time the derivative’s fair value will be recognized in earnings. Ineffective portions of a hedging derivative’s change in fair value are immediately recognized in earnings. Adoption of SFAS Nos. 133/138 resulted in a transition adjustment gain to AOCL of $6.6 million, net of $2.8 million in income taxes, for the cumulative effect on prior years; there was no cumulative effect on earnings. Excluding the transition adjustment, the effect of this accounting change increased AOCL for the six months ended June 30, 2002 and 2001 by $5.2 million and $3.4 million, net of $3.6 million and $2.7 million in income taxes, and increased income by an insignificant amount for the same periods, but did not affect income per diluted share. For the six months ended June 30, 2002, gains of $2.4 million, net of $1.4 million in taxes, were reclassified from AOCL to earnings. In the first six months of 2001, losses of $1.3 million, net of $1.2 million in taxes, were reclassified from AOCL to earnings.
 
Note C—Environmental Contingencies
 
The Company’s operations are 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 refineries, oil and gas fields, gasoline stations, and terminals, for which known or potential obligations for environmental remediation exist.
 
Under the Company’s accounting policies, an environmental liability is recorded when an obligation is probable and the cost can be reasonably estimated. If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used. Recorded liabilities are reviewed quarterly. Actual cash expenditures often occur one or more years after a liability is recognized.
 
The Company’s reserve for remedial obligations, which is included in “Deferred Credits and Other Liabilities” in the Consolidated Balance Sheets, contains certain amounts that are based on anticipated regulatory approval for proposed remediation of a former refinery waste site. If regulatory authorities require more costly alternatives than the proposed processes, future expenditures could exceed the amount reserved by up to an estimated $3 million.
 
The Company has received notices from the U.S. Environmental Protection Agency (EPA) that it is currently considered a Potentially Responsible Party (PRP) at three Superfund sites and has also been assigned responsibility by defendants at another Superfund site. 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 has reason to believe that it is a de minimus party as to ultimate responsibility at the four sites. The Company does not expect that its related remedial costs will be material to its financial condition or its results of operations, and it has not provided a reserve for remedial costs on Superfund sites. Additional information may become known in the future that would alter this assessment, including any requirement to bear a pro rata share of costs attributable to nonparticipating PRPs or indications of additional responsibility by the Company.
 
The Company does not believe that these or other known environmental matters will have a material adverse effect on its financial condition. There is the possibility that expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. Such expenditures could materially affect the results of operations in a future period.
 
Certain environmental expenditures are likely to be recovered by the Company from other sources, primarily environmental funds maintained by certain states. Since no assurance can be given that future recoveries from other sources will occur, the Company has not recognized a benefit for likely recoveries at June 30, 2002.

6

 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
 
Note D—Other Contingencies
 
The Company’s operations and earnings have been and may be affected by various other 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; 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, 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.
 
The Company and its subsidiaries are engaged in a number of legal proceedings, all of which the Company considers routine and incidental to its business and none of which is considered material. 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, 2002 the Company had contingent liabilities of $34.5 million under certain financial guarantees and $31.4 million on outstanding letters of credit.
 
Note E—Earnings per Share
 
Net income was used as the numerator in computing both basic and diluted income per Common share for the three-month and six-month periods ended June 30, 2002 and 2001. The following table reconciles the weighted-average shares outstanding used for these computations.
 
    
Three Months Ended
June 30,
   
Six Months Ended
June 30,
    
2002
   
2001
   
2002
   
2001
    
(Weighted-average shares)
Reconciliation of Shares Outstanding
                    
Basic method
   
45,784,073
   
45,206,604
   
45,635,493
   
45,139,453
Dilutive stock options
   
349,359
   
437,853
   
394,017
   
350,641
    
  
  
  
Diluted method
   
46,133,432
   
45,644,457
   
46,029,510
   
45,490,094
    
  
  
  
 
All stock options outstanding during each of the periods presented were dilutive.
 
Note F—Financial Instruments and Risk Management
 
Murphy utilizes derivative instruments on a limited basis 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 trading 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.
 
•
 
Interest Rate Risks—Murphy has variable-rate debt obligations that expose the Company to the effects of changes in interest rates. To partially reduce its exposure to interest rate risk, Murphy has interest rate swap agreements with notional amounts totaling $50 million at June 30, 2002 to hedge fluctuations in cash flows of a similar amount of variable rate debt. Interest rate swaps with notional amounts totaling $50 million matured during the second quarter of 2002. The remaining swaps mature in 2004. Under the interest rate swaps, the Company pays fixed rates averaging 6.17% over their composite lives and receives variable rates which averaged 2.02% at June 30, 2002. The variable rate received by the Company under each contract is repriced quarterly. The Company has a risk management control system to monitor interest rate cash flow risk attributable to the Company’s outstanding and forecasted debt obligations as well as the offsetting interest rate swaps. The control system involves using analytical techniques, including cash flow sensitivity analysis, to estimate the impact of interest rate changes on future cash flows. The fair value of the effective portions of the interest rate swaps and changes thereto is deferred in Accumulated Other Comprehensive Loss (AOCL) and is subsequently reclassified into Interest Expense in the periods in which the hedged interest payments on the variable-rate debt affect earnings. For the periods ended June 30, 2002 and 2001, the income effect from cash

7

 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
 
Note F—Financial Instruments and Risk Management (Contd.)
 
flow hedging ineffectiveness of interest rates was insignificant. The fair value of the interest rate swaps are estimated using projected Federal funds rates, Canadian overnight funding rates and LIBOR forward curve rates obtained from published indices and counterparties. The estimated fair value approximates the values based on quotes from each of the counterparties.
 
•
 
Natural Gas Fuel Price Risks—The Company purchases natural gas as fuel at its Meraux, Louisiana refinery, and as such, is subject to commodity price risk related to the purchase price of this gas. Murphy has hedged the cash flow risk associated with the cost of a portion of the natural gas it will purchase in 2004 through 2006 by entering into natural gas swap contracts with a total notional volume of 9.2 million British Thermal Units (MMBTU). Under the natural gas swaps, the Company pays a fixed rate averaging $2.78 per MMBTU and receives a floating rate in each month of settlement based on the average NYMEX price for the final three trading days of the month. Murphy has a risk management control system to monitor natural gas price risk attributable both to forecasted natural gas fuel requirements and to Murphy’s natural gas swaps. The control system involves using analytical techniques, including various correlations of natural gas purchase prices to futures prices, to estimate the impact of changes in natural gas fuel prices on Murphy’s cash flows. The fair value of the effective portions of the natural gas swaps and changes thereto is deferred in AOCL and is subsequently reclassified into Crude Oil, Products and Related Operating Expenses in the periods in which the hedged natural gas fuel purchases affect earnings. For the periods ended June 30, 2002 and 2001, the income effect from cash flow hedging ineffectiveness was insignificant.
 
•
 
Natural Gas Sales Price Risks—The sales price of natural gas produced by the Company is subject to commodity price risk. Murphy has hedged the cash flow risk associated with the sales price for a portion of the natural gas it will produce in the United States and Canada from July 2002 to October 2002 by entering into financial contracts known as natural gas swaps and collars. The swaps cover a combined notional volume averaging 47,000 MMBTU equivalents per day and require Murphy to pay the average relevant index (NYMEX or AECO “C”) price for each month and receive an average price of $3.38 per MMBTU equivalent. The natural gas collars are for a combined notional volume averaging 48,000 MMBTU equivalents per day and based upon the relevant index prices, provide Murphy with an average floor price of $2.73 per MMBTU and an average ceiling price of $4.88 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 natural gas price risk pertaining to a portion of gas sales from properties Murphy acquired from Beau Canada in 2000 was limited by natural gas swap agreements that expired in October 2001 that were obtained in the acquisition. These agreements hedged fluctuations in cash flows resulting from such risk. Certain swaps required Murphy to pay a floating price and receive a fixed price and were partially offset by swaps on a lesser volume that required Murphy to pay a fixed price and receive a floating price. The fair value of these swaps was recorded as a net liability upon the acquisition of Beau Canada and was adjusted on January 1, 2001 upon transition to SFAS 133. Net payments by the Company were recorded as a reduction of the associated liability, with any differences recorded as an adjustment of natural gas revenue.
 
The fair values of the effective portions of the natural gas swaps and collars and changes thereto are deferred in AOCL and are subsequently reclassified into Crude Oil and Natural Gas Sales in the periods in which the hedged natural gas sales affect earnings. For the period ended June 30, 2002, Murphy’s earnings were increased by $.3 million from recognition of the ineffective portions of cash flow hedging arising from the natural gas swaps and collars in the United States and western Canada. Murphy’s earnings in the 2001 period were not significantly affected by cash flow hedging ineffectiveness.
 
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 or AECO “C” index futures price or natural gas price quotes from counterparties.

8

 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
 
Note F—Financial Instruments and Risk Management (Contd.)
 
•
 
Crude Oil Purchase Price Risks—Each month, the Company purchases crude oil as the primary feedstock for its U.S. refineries. Prior to April 2000, the Company was a party to crude oil swap agreements that limited the exposure of its U.S. refineries to the risks of fluctuations in cash flows resulting from changes in the prices of crude oil purchases in 2001 and 2002. Under each swap, Murphy would have paid a fixed crude oil price and would have received a floating price during the agreement’s contractual maturity period. In April 2000, the Company settled certain of the swaps and entered into offsetting contracts for the remaining swap agreements, locking in a total net gain of $7.7 million. The fair values of these settlement gains were recorded in AOCL as part of the transition adjustment at January 1, 2001 and are recognized as a reduction of costs of crude oil purchases in the period the forecasted transaction occurs. During the six-month period ended June 30, 2002, pretax gains of $3.6 million were reclassified from AOCL into earnings. No gains were reclassified into earnings in the second quarter of 2002 or in the six-month period ended June 30, 2001. The fair value of the offsetting crude oil swap contracts is based on the fixed swap price and the NYMEX crude oil futures price.
 
The Company expects to reclassify approximately $4 million in after-tax gains from AOCL into earnings during the next 12 months as the forecasted transactions covered by hedging instruments actually occur. All forecasted transactions currently being hedged are expected to occur by December 2006.
 
Note G—Accumulated Other Comprehensive Loss
 
Net gains (losses) in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets at June 30, 2002 and December 31, 2001 were as follows.
 
    
June 30, 2002
       
December 31, 2001
  
    
(Millions of dollars)
  
Foreign currency translation loss, net
   
$
(35.4
)
     
(87.8
)
Cash flow hedge gains, net
   
 
9.8
 
     
4.5
 
    
    
Accumulated other comprehensive loss
   
$
(25.6
)
     
(83.3
)
    
    
 
Note H—Financing Arrangements
 
In May 2002, the Company sold $350 million of 6.375 percent coupon notes due in 2012. Interest is payable November 1, 2002 and semiannually thereafter. The Company used a portion of the net proceeds to refinance outstanding indebtedness under existing credit facilities and will use the remaining proceeds to fund ongoing capital projects and for other general purposes.
 
Note I—Property, Plant and Equipment
 
During May, the Company and the U.S. government reached an agreement in principle where the U.S. government will pay Murphy $23 million to relinquish seven of nine leases in the Destin Dome field off the coast of Florida. As part of the agreement, the Company will have a 100% interest in the remaining two Destin Dome leases. These leases will run through 2022, with no development application allowed until at least 2012. The Company must obtain permission of both the U.S. government and the State of Florida to perform development operations during the 20-year lease term. There will be no gain or loss recorded in connection with the agreement, and after receipt of the proceeds, Murphy will have approximately $22.5 million of net costs in Property, Plant and Equipment associated with the remaining two leases. Should the U.S. government and/or the State of Florida refuse to permit development by the Company prior to expiration of the leases, the Company’s net investment would be impaired and charged to expense.

9

 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
 
Note J—Business Segments
 
    
Total Assets at June 30, 2002
   
Three Months Ended
June 30, 2002
     
Three Months Ended
June 30, 2001
  
       
External
Revenues
     
Intersegment
Revenues
   
Income
(Loss)
     
External
Revenues
     
Intersegment
Revenues
   
Income
(Loss)
  
    
(Millions of dollars)
  
Exploration and production*
                                             
United States
   
$
644.5
   
30.7
     
12.7
   
(4.1
)
   
53.2
     
13.7
   
24.6
 
Canada
   
 
1,340.9
   
181.7
     
—  
   
54.0
 
   
119.3
     
9.1
   
23.8
 
United Kingdom
   
 
239.9
   
39.0
     
—  
   
9.2
 
   
51.2
     
—  
   
21.4
 
Ecuador
   
 
76.5
   
7.9
     
—  
   
3.3
 
   
10.2
     
—  
   
4.3
 
Malaysia
   
 
41.6
   
—  
     
—  
   
(32.1
)
   
—  
     
—  
   
(7.8
)
Other international
   
 
7.9
   
.5
     
—  
   
(.7
)
   
.4
     
—  
   
(5.7
)
    
  
    
  
  
    
  
Total
   
 
2,351.3
   
259.8
     
12.7
   
29.6
 
   
234.3
     
22.8
   
60.6
 
    
  
    
  
  
    
  
Refining and marketing
                                             
United States
   
 
955.5
   
773.9
     
—  
   
(9.8
)
   
838.7
     
—  
   
34.3
 
United Kingdom
   
 
205.2
   
100.0
     
—  
   
1.8
 
   
83.7
     
—  
   
2.0
 
Canada
   
 
1.1
   
—  
     
—  
   
—  
 
   
140.4
     
.1
   
68.4
 
    
  
    
  
  
    
  
Total
   
 
1,161.8
   
873.9
     
—  
   
(8.0
)
   
1,062.8
     
.1
   
104.7
 
    
  
    
  
  
    
  
Total operating segments
   
 
3,513.1
   
1,133.7
     
12.7
   
21.6
 
   
1,297.1
     
22.9
   
165.3
 
Corporate and other
   
 
265.5
   
1.0
     
—  
   
(7.6
)
   
3.3
     
—  
   
(2.7
)
    
  
    
  
  
    
  
Total consolidated
   
$
3,778.6
   
1,134.7
     
12.7
   
14.0
 
   
1,300.4
     
22.9
   
162.6
 
    
  
    
  
  
    
  
 
    
Six Months Ended
June 30, 2002
     
Six Months Ended
June 30, 2001
  
    
External Revenues
     
Intersegment Revenues
   
Income (Loss)
     
External Revenues
     
Intersegment Revenues
   
Income (Loss)
  
    
(Millions of dollars)
  
Exploration and production*
                                        
United States
   
$
53.8
     
22.6
   
(6.7
)
   
132.6
     
30.9
   
55.7
 
Canada
   
 
302.3
     
—  
   
71.8
 
   
219.0
     
30.0
   
51.9
 
United Kingdom
   
 
84.5
     
—  
   
22.4
 
   
101.5
     
—  
   
41.5
 
Ecuador
   
 
13.5
     
—  
   
4.1
 
   
20.3
     
—  
   
8.1
 
Malaysia
   
 
—  
     
—  
   
(40.1
)
   
—  
     
—  
   
(9.0
)
Other international
   
 
1.1
     
—  
   
(1.2
)
   
.9
     
—  
   
(7.0
)
    
    
  
  
    
  
Total
   
 
455.2
     
22.6
   
50.3
 
   
474.3
     
60.9
   
141.2
 
    
    
  
  
    
  
Refining and marketing
                                        
United States
   
 
1,322.3
     
—  
   
(21.3
)
   
1,544.9
     
—  
   
49.3
 
United Kingdom
   
 
185.1
     
—  
   
(.4
)
   
162.2
     
—  
   
3.8
 
Canada
   
 
—  
     
—  
   
—  
 
   
301.4
     
.2
   
71.2
 
    
    
  
  
    
  
Total
   
 
1,507.4
     
—  
   
(21.7
)
   
2,008.5
     
.2
   
124.3
 
    
    
  
  
    
  
Total operating segments
   
 
1,962.6
     
22.6
   
28.6
 
   
2,482.8
     
61.1
   
265.5
 
Corporate and other
   
 
2.0
     
—  
   
(12.1
)
   
7.0
     
—  
   
(5.1
)
    
    
  
  
    
  
Total consolidated
   
$
1,964.6
     
22.6
   
16.5
 
   
2,489.8
     
61.1
   
260.4
 
    
    
  
  
    
  
*
 
Additional details about results of operations are presented in the tables on page 17.

10

 
ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
Results of Operations
 
Murphy’s net income in the second quarter of 2002 totaled $14 million, $.30 a diluted share, compared to income of $95 million, $2.08 a diluted share, before a special item in the second quarter a year ago. Net income for the second quarter of 2001 totaled $162.6 million, $3.56 a diluted share, and included a gain on sale of Canadian pipeline assets of $67.6 million, $1.48 a diluted share.
 
In the current quarter, the Company’s exploration and production operations earned $29.6 million, a decrease of $31 million from $60.6 million earned in the 2001 period. The decline in income was primarily the result of significantly lower North American natural gas sales prices and higher exploration expenses partially offset by higher oil and gas sales volumes. The Company’s refining and marketing operations incurred a loss of $8 million in the 2002 period compared to earnings of $37.1 million before special items for the three months ended June 30, 2001. Due to negative margins throughout much of the period, Murphy’s U.S. operations lost $9.8 million in the just completed quarter compared to a profit of $34.3 million in the same quarter a year ago.
 
For the first six months of 2002, net income totaled $16.5 million, $.36 a diluted share, compared to income of $192.8 million, $4.24 a diluted share, before a special item for the first half of 2001. Net income a year ago was $260.4 million, $5.72 a diluted share, including an after-tax benefit of $67.6 million, $1.48 a diluted share, from the sale of the Company’s pipeline assets in Canada.
 
Exploration and production earnings in the first six months of 2002 were down $90.9 million from the prior year, mainly due to decreases in North American natural gas sales prices and higher exploration expenses, partially offset by record crude oil and natural gas sales volumes. The Company’s refining and marketing operations incurred a loss of $21.7 million in the first half of 2002 compared to earnings of $56.7 million before a special item in the 2001 period. U.S. refining margins were significantly lower in the 2002 period compared to a year ago.
 
The Company’s worldwide effective tax rate is significantly higher than the expected tax rate primarily because no tax benefit has been recorded for exploration expenses incurred in Malaysia.
 
Exploration and Production
 
Results of exploration and production operations are presented by geographic segment below.
 
    
Income (Loss)
  
    
Three Months Ended
June 30,
     
Six Months Ended
June 30,
  
    
2002
     
2001
     
2002
     
2001
  
    
(Millions of dollars)
  
Exploration and production
                              
United States
   
$
(4.1
)
   
24.6
 
   
(6.7
)
   
55.7
 
Canada
   
 
54.0
 
   
23.8
 
   
71.8
 
   
51.9
 
United Kingdom
   
 
9.2
 
   
21.4
 
   
22.4
 
   
41.5
 
Ecuador
   
 
3.3
 
   
4.3
 
   
4.1
 
   
8.1
 
Malaysia
   
 
(32.1
)
   
(7.8
)
   
(40.1
)
   
(9.0
)
Other International
   
 
(.7
)
   
(5.7
)
   
(1.2
)
   
(7.0
)
    
  
  
  
Total
   
$
29.6
 
   
60.6
 
   
50.3
 
   
141.2
 
    
  
  
  
 
Exploration and production operations in the United States reported a loss of $4.1 million in the second quarter of 2002 compared to earnings of $24.6 million a year ago. This decline was primarily due to lower sales prices for natural gas and oil, lower oil and natural gas sales volumes, and a $19.9 million increase in exploration expenses. Sales of natural gas averaged 99 million cubic feet a day, down from 119 million in the second quarter of 2001 due to lower production in the Gulf of Mexico. U.S. production expenses were up $1.6 million or 13%, primarily because of higher well workover costs.
 
Operations in the United States for the six months ended June 30, 2002 reflected a loss of $6.7 million compared to earnings of $55.7 million from 2001. The decrease was primarily due to lower natural gas sales prices and lower production volumes in the Gulf of Mexico, coupled with higher exploration expenses and increased well workover costs.

11

 
ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
 
Results of Operations (Contd.)
 
Exploration and Production (Contd.)
 
Operations in Canada earned $54 million this quarter compared to $23.8 million a year ago as record production of oil and natural gas were offset by declines in average oil and natural gas sales prices. Also exploration expenses in the 2002 period declined $19.2 million from a year ago. Oil and gas liquids sales in Canada averaged 55,916 barrels a day, an increase of 50% over the prior year, primarily because of higher sales volumes at Hibernia and initial production and sales from the Terra Nova field in 2002, partially offset by a lower production at Syncrude due to maintenance activities. Canadian natural gas sales averaged 231 million cubic feet a day in the current quarter, up 52%, with the increase primarily attributable to higher production from the Ladyfern field. Higher oil and gas sales volumes caused a $7.2 million increase in Canadian production expenses in the 2002 quarter over the 2001 period.
 
In the first half of 2002, Canada operations earned $71.8 million compared to $51.9 million a year ago. Higher sales volumes for oil and natural gas were offset by declines in average oil and natural gas sales prices. Exploration expenses also declined $9.6 million versus 2001.
 
U.K. operations earned $9.2 million in the current quarter, down from $21.4 million in the prior year. Revenues from sales of oil and gas liquids in the United Kingdom decreased 16% primarily due to the timing of liftings and lower sales prices for U.K. crude oil. Income for the 2002 six-month period was $22.4 million compared to $41.5 million a year ago. The decline was primarily due to lower sales prices for U.K. crude oil, higher production expenses and a one-time tax adjustment. In April 2002, U.K. tax authorities announced a corporation tax rate increase from 30% to 40% for profits associated with North Sea oil production. It was also announced that the first-year allowance for North Sea capital expenditures would increase from 25% to 100%. During the second quarter of 2002, the Company recorded a $2 million tax charge due to the rate change. Based on current Company estimates, the net effect of these changes is expected to reduce U.K. income during the last half of 2002 by approximately $4 million.
 
Operations in Ecuador earned $3.3 million in the second quarter of 2002 compared to $4.3 million a year ago, while Malaysia and other international operations reported losses of $32.1 million and $.7 million, respectively, compared to losses of $7.8 million and $5.7 million in 2001. The higher loss in Malaysia in the current period was primarily due to dry holes costs associated with two unsuccessful deepwater wells in Block K. The higher loss in other international operations in the 2001 period was the result of an unsuccessful well offshore Ireland. Crude oil sales in Ecuador decreased 29% which more than offset an increase in the average sales price. Sales volumes in Ecuador were adversely affected by pipeline restrictions. Production expenses in Ecuador decreased by $.9 million in the 2002 period.
 
For the first six months of 2002, earnings in Ecuador were $4.1 million compared to $8.1 million for the 2001 period, while Malaysia and other international operations reported losses of $40.1 million and $1.2 million, respectively, compared to losses of $9 million and $7 million a year ago. Sales volumes in Ecuador decreased 31% in the first half of 2002 due to pipeline capacity restrictions. The higher loss in Malaysia was primarily due to the previously mentioned dry holes.
 
On a worldwide basis, the Company’s crude oil and condensate prices averaged $23.88 a barrel in the current quarter, an increase of 4% from the average of $22.97 in the 2001 period. The increase in the average price in 2002 versus 2001 was due to much stronger heavy oil prices in the 2002 period. Average crude oil and liquids production was a quarterly record of 78,050 barrels a day, up 20% over last year, while average sales volumes increased 19% to 83,313 barrels a day due to initial production and sales from Terra Nova. North American natural gas sales prices averaged $3.03 per MCF in the second quarter compared to $4.33 per MCF in the same quarter of 2001. Total natural gas sales volumes were also a Company record and averaged 336 million cubic feet a day in 2002, up 18% from the 2001 quarter. The tables on page 17 provide additional details of the results of exploration and production operations for the first half of each year.

12

 
ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
 
Results of Operations (Contd.)
 
Exploration and Production (Contd.)
 
Selected operating statistics for the three and six-month periods ended June 30, 2002 and 2001 follow.
 
    
Three Months
Ended June 30,
   
Six Months
Ended June 30,
    
2002
   
2001
   
2002
   
2001
Net crude oil, condensate and gas liquids produced—barrels per day
   
 
78,050
   
64,913
   
76,181
   
66,973
United States
   
 
5,768
   
6,033
   
5,975
   
5,770
Canada—light
   
 
3,107
   
4,314
   
3,585
   
4,448
  —heavy
   
 
9,469
   
11,647
   
9,595
   
12,320
  —offshore
   
 
26,317
   
8,980
   
23,057
   
8,967
   —synthetic
   
 
8,828
   
9,254
   
10,078
   
9,800
United Kingdom
   
 
19,796
   
19,242
   
19,415
   
20,029
Ecuador
   
 
4,765
   
5,443
   
4,476
   
5,639
                       
Net crude oil, condensate and gas liquids sold—barrels per day
   
 
83,313
   
69,932
   
81,769
   
67,855
United States
   
 
5,768
   
6,033
   
5,975
   
5,770
Canada—light
   
 
3,107
   
4,314
   
3,585
   
4,448
  —heavy
   
 
9,469
   
11,647
   
9,595
   
12,320
  —offshore
   
 
34,512
   
12,030
   
28,010
   
9,606
   —synthetic
   
 
8,828
   
9,254
   
10,078
   
9,800
United Kingdom
   
 
17,348
   
20,650
   
20,282
   
19,734
Ecuador
   
 
4,281
   
6,004
   
4,244
   
6,177
                       
Net natural gas sold—thousands of cubic feet per day
   
 
335,954
   
283,979
   
322,696
   
266,486
United States
   
 
99,312
   
119,150
   
100,297
   
121,981
Canada
   
 
231,154
   
152,469
   
215,408
   
129,366
United Kingdom
   
 
5,488
   
12,360
   
6,991
   
15,139
                       
Total net hydrocarbons produced—equivalent barrels per day(1)
   
 
134,042
   
112,243
   
129,964
   
111,387
                       
Total net hydrocarbons sold—equivalent barrels per day(1)
   
 
139,305
   
117,262
   
135,552
   
112,269
                       
Weighted average sales prices Crude oil and condensate—dollars a barrel(2)
                      
United States
   
$
24.84
   
25.52
   
22.48
   
26.45
Canada(3)—light
   
 
24.67
   
24.52
   
20.41
   
24.75
      —heavy
   
 
17.49
   
10.86
   
15.42
   
10.11
      —offshore
   
 
25.47
   
26.76
   
24.13
   
26.84
      —synthetic
   
 
26.06
   
27.55
   
23.36
   
27.88
United Kingdom
   
 
23.56
   
25.91
   
22.03
   
26.47
Ecuador
   
 
20.54
   
18.63
   
17.74
   
18.18
                       
Natural gas—dollars a thousand cubic feet
                      
United States(2)
  
$
3.46
   
4.89
   
3.03
   
6.07
Canada(3)
   
 
2.85
   
3.89
   
2.52
   
4.67
United Kingdom(3)
   
 
2.84
   
2.26
   
2.91
   
2.42
(1)
 
Natural gas converted on an energy equivalent basis of 6:1
(2)
 
Includes intracompany transfers at market prices.
(3)
 
U.S. dollar equivalent.

13

 
ITEM2.    MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
 
Results of Operations (Contd.)
 
Refining and Marketing
 
Results of refining and marketing operations are presented below by geographic segment.
 
    
Income (Loss)
    
Three Months Ended
June 30,
   
Six Months Ended
June 30,
    
2002
     
2001
   
2002
     
2001
    
(Millions of dollars)
Refining and marketing
                          
United States
   
$
(9.8
)
   
34.3
   
(21.3
)
   
49.3
United Kingdom
   
 
1.8
 
   
2.0
   
(.4
)
   
3.8
Canada
   
 
—  
 
   
.8
   
—  
 
   
3.6
    
  
  
  
Income (loss) before special items
   
 
(8.0
)
   
37.1
   
(21.7
)
   
56.7
Gain on sale of assets
   
 
—  
 
   
67.6
   
—  
 
   
67.6
    
  
  
  
Total income (loss)
   
$
(8.0
)
   
104.7
   
(21.7
)
   
124.3
    
  
  
  
 
Refining and marketing operations in the United States reported a loss of $9.8 million during the second quarter of 2002 compared to earnings of $34.3 million in the same period a year ago. The Company’s U.S. refining margins were significantly lower in the current quarter compared to margins in the same quarter of 2001. U.S. petroleum product sales averaged 179,376 barrels a day in 2002, a 6.4% increase from the second quarter of 2001. Earnings in the United Kingdom were $1.8 million in the 2002 period compared to $2 million a year ago. Worldwide refinery inputs were 161,363 barrels a day in the second quarter of 2002 compared to 172,890 in the 2001 quarter, and petroleum product sales were 214,708 barrels a day, up from 192,167 a year ago. U.S. refinery inputs were significantly lower in the 2002 period due to unscheduled outages of FCC units at the Meraux refinery. Earnings from purchasing, transporting and reselling crude oil in Canada were $.8 million in the 2001 quarter. The Company sold its Canadian pipeline and trucking operations in May 2001 resulting in a net gain of $67.6 million.
 
Refinery and marketing operations in the United States in the first half of 2002 reported a loss of $21.3 million compared to earnings of $49.3 million in the 2001 period. U.S. refining margins were negative during much of the current period compared to the positive margins experienced a year ago. The 2002 results include a net gain of $3.5 million from sale of the Company’s interest in Butte Pipe Line. Results in the United Kingdom reflected a loss of $.4 million in the six months ended June 30, 2002 compared to earnings of $3.8 million in 2001 due to lower refinery margins compared to the same period a year ago. Prior to the sale in the second quarter 2001, the Company earned $3.6 million from purchasing, transporting and reselling crude oil in Canada.
 
Selected operating statistics for the three-month and six-month periods ended June 30, 2002 and 2001 follow.
 
    
Three Months Ended
June 30,
   
Six Months Ended
June 30,
    
2002
   
2001
   
2002
   
2001
Refinery inputs—barrels a day
   
161,363
   
172,890
   
157,952
   
175,777
United States
   
123,568
   
147,751
   
120,660
   
149,692
United Kingdom
   
37,795
   
25,139
   
37,292
   
26,085
Petroleum products sold—barrels a day
   
214,708
   
192,167
   
203,079
   
190,643
United States
   
179,376
   
168,537
   
168,501
   
166,559
Gasoline
   
112,651
   
93,102
   
104,821
   
89,723
Kerosine
   
4,582
   
9,101
   
6,505
   
10,731
Diesel and home heating oils
   
39,071
   
39,958
   
37,407
   
41,322
Residuals
   
14,323
   
17,948
   
13,687
   
17,914
Asphalt, LPG and other
   
8,749
   
8,428
   
6,081
   
6,869
United Kingdom
   
35,332
   
23,630
   
34,578
   
24,084
Gasoline
   
12,865
   
9,502
   
12,856
   
9,440
Kerosine
   
2,438
   
1,418
   
2,546
   
1,997
Diesel and home heating oils
   
15,276
   
8,484
   
14,570
   
7,947
Residuals
   
3,412
   
1,196
   
3,116
   
1,857
LPG and other
   
1,341
   
3,030
   
1,490
   
2,843

14

 
MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
 
Results of Operations (Contd.)
 
Corporate and other
 
The net costs of corporate activities, which include interest income and expense and corporate overhead not allocated to operating functions, was $7.6 million in the current quarter compared to $2.7 million in the 2001 quarter. In the first six months of 2002, corporate activities reflected a net cost of $12.1 million compared to $5.1 million a year ago. The net costs in both the 2002 periods increased compared to the respective 2001 period due to a decrease in interest income earned caused by lower levels of invested cash balances coupled with higher net interest expense due to increased long-term borrowings.
 
Financial Condition
 
Net cash provided by operating activities was $171 million for the first six months of 2002 compared to $351.9 million for the same period in 2001. Changes in operating working capital other than cash and cash equivalents used cash of $96.4 million and $35.9 million in the first six months of 2002 and 2001, respectively. Cash from operating activities was reduced by expenditures for refinery turnarounds and abandonment of oil and gas properties totaling $9.8 million in the current year and $9.9 million in 2001. Other predominant uses of cash in each year were for capital expenditures, which including amounts expensed, are summarized in the following table, and for dividends, which totaled $34.2 million in 2002 and $33.8 in 2001.
 
    
Six Months Ended June 30,
  
    
2002
     
2001
  
    
(Millions of dollars)
  
Capital Expenditures
                
Exploration and production
   
$
325.3
 
   
344.9
 
Refining and marketing
   
 
109.1
 
   
67.0
 
Corporate and other
   
 
.5
 
   
4.1
 
    
  
Total capital expenditures
   
 
434.9
 
   
416.0
 
Geological, geophysical and other exploration expenses charged to income
   
 
(18.7
)
   
(22.2
)
    
  
Total property additions and dry holes
   
$
416.2
 
   
393.8
 
    
  
 
Working capital at June 30, 2002 was $191.1 million, up $152.5 million from December 31, 2001. 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 $109.7 million below current costs at June 30, 2002.
 
At June 30, 2002, long-term notes payable of $712.8 million were up $296.7 million from December 31, 2001 due to issuance of $350 million of 6.375% notes in May 2002. The Company used a portion of the net proceeds to refinance outstanding indebtedness under existing credit facilities and will use the remaining proceeds to fund ongoing capital projects and for other general purposes. Long-term nonrecourse debt of a subsidiary was $92.5 million, down $12.2 million from December 31, 2001, primarily due to repayments. A summary of capital employed at June 30, 2002 and December 31, 2001 follows.
 
    
June 30, 2002
   
December 31, 2001
    
Amount
   
%
   
Amount
   
%
    
(Millions of dollars)
Capital Employed    
                      
Notes payable
   
$
712.8
   
30
   
416.1
   
21
Nonrecourse debt of a subsidiary
   
 
92.5
   
4
   
104.7
   
5
Stockholders’ equity
   
 
1,571.4
   
66
   
1,498.2
   
74
    
  
  
  
    
$
2,376.7
   
100
   
2,019.0
   
100
    
  
  
  
 
Accounting Matters
 
As described in Note B on page 5 of this Form 10-Q report, Murphy adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, and SFAS No. 144, Accounting for the Impairment of Disposal of Long-Lived Assets effective, January 1, 2002.

15

 
MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
 
Outlook
 
For the third quarter of 2002, the Company expects worldwide production to average approximately 117,000 barrels of oil equivalent a day, with lower volumes due to downtime for routine maintenance at Hibernia, Terra Nova and North Sea fields, and expected production decline at the Ladyfern field. Sales volumes are projected to average approximately 111,000 barrels of oil equivalent per day. In July 2002, the Company’s U.S. refining and marketing operations were experiencing losses due to negative refining margins.
 
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 was a party to interest rate swaps at June 30, 2002 with notional amounts totaling $50 million that were designed to hedge fluctuations in cash flows of a similar amount of variable-rate debt. These swaps mature in 2004. The swaps require the Company to pay an average interest rate of 6.17% over their composite lives, and at June 30, 2002, the interest rate to be received by the Company averaged 2.02%. 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 $3.2 million at June 30, 2002.
 
At June 30, 2002, 12% of the Company’s debt had variable interest rates and 4.6% was denominated in Canadian dollars. Based on debt outstanding at June 30, 2002, a 10% increase in variable interest rates would increase the Company’s interest expense approximately $.1 million for the next 12 months after including the favorable effect resulting from lower net settlement payments under the aforementioned interest rate swaps. A 10% increase in the exchange rate of the Canadian dollar versus the U.S. dollar would increase interest expense for the next 12 months by $.1 million for debt denominated in Canadian dollars.
 
Murphy was a party to natural gas price swap agreements at June 30, 2002 for a total notional volume of 9.2 MMBTU that are intended to hedge a portion of 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 during 2004 through 2006. In each month of settlement, the swaps require Murphy to pay an average natural gas price of $2.78 an MMBTU and to receive the average NYMEX price for the final three trading days of the month. At June 30, 2002, the estimated fair value of these agreements was recorded as an asset of $9.8 million. A 10% increase in the average NYMEX price of natural gas would have increased this asset by $3.2 million, while a 10% decrease would have reduced the asset by a similar amount.
 
In addition, the Company was a party to natural gas swap agreements and natural gas collar agreements at June 30, 2002 that are intended to hedge the financial exposure of a limited portion of its U.S. and Canadian natural gas production to changes in gas sales prices through October 2002. The swaps are for a combined notional volume that averages 47,700 MMBTU equivalents a day through October 2002 and require Murphy to pay the average relevant index price for each month and receive an average price of $3.38 per MMBTU. The collars are for a combined notional volume of 48,000 MMBTU equivalents a day and based upon the relevant index prices provide Murphy with an average floor price of $2.73 per MMBTU and an average ceiling price of $4.88 per MMBTU. At June 30, 2002, the estimated fair value of these agreements was recorded as an asset of $7.4 million. A 10% increase in the average index price of natural gas would have reduced this asset by $2.9 million, while a 10% decrease would have increased the asset by a similar amount.

16

 
OIL AND GAS OPERATING RESULTS (unaudited)
 
    
United States
     
Canada
   
United Kingdom
   
Ecuador
   
Malaysia
     
Other
     
Synthetic Oil- Canada
   
Total
    
(Millions of dollars)
Three Months Ended June 30, 2002
                                                
Oil and gas sales, other operating revenues
   
$
43.4
 
   
160.8
   
39.0
   
7.9
   
—  
 
   
.5
 
   
20.9
   
272.5
Production expenses
   
 
14.2
 
   
25.4
   
8.4
   
3.1
   
—  
 
   
—  
 
   
11.1
   
62.2
Depreciation, depletion and amortization
   
 
10.0
 
   
50.0
   
8.1
   
1.3
   
.2
 
   
—  
 
   
2.1
   
71.7
Exploration expenses
                                                
Dry holes
   
 
17.5
 
   
1.0
   
—  
   
—  
   
31.2
 
   
—  
 
   
—  
   
49.7
Geological and geophysical
   
 
1.3
 
   
1.3
   
—  
   
—  
   
.2
 
   
—  
 
   
—  
   
2.8
Other
   
 
1.8
 
   
.4
   
.3
   
—  
   
.5
 
   
—  
 
   
—  
   
3.0
    
  
  
  
  
  
  
  
    
 
20.6
 
   
2.7
   
.3
   
—  
   
31.9
 
   
—  
 
   
—  
   
55.5
Undeveloped lease amortization
   
 
2.7
 
   
3.6
   
—  
   
—  
   
—  
 
   
—  
 
   
—  
   
6.3
    
  
  
  
  
  
  
  
Total exploration expenses
   
 
23.3
 
   
6.3
   
.3
   
—  
   
31.9
 
   
—  
 
   
—  
   
61.8
    
  
  
  
  
  
  
  
Selling and general expenses
   
 
2.2
 
   
3.6
   
.8
   
.2
   
—  
 
   
1.4
 
   
—  
   
8.2
Income tax provisions (benefits)
   
 
(2.2
)
   
26.7
   
12.2
   
—  
   
—  
 
   
(.2
)
   
2.5
   
39.0
    
  
  
  
  
  
  
  
Results of operations (excluding
  corporate overhead and interest)
   
$
(4.1
)
   
48.8
   
9.2
   
3.3
   
(32.1
)
   
(.7
)
   
5.2
   
29.6
    
  
  
  
  
  
  
  
Three Months Ended June 30, 2001
                                                
Oil and gas sales, other operating revenues
   
$
66.9
 
   
105.1
   
51.2
   
10.2
   
—  
 
   
.4
 
   
23.3
   
257.1
Production expenses
   
 
12.6
 
   
18.2
   
7.6
   
4.0
   
—  
 
   
—  
 
   
13.3
   
55.7
Depreciation, depletion and amortization
   
 
10.4
 
   
23.7
   
8.9
   
1.8
   
.1
 
   
—  
 
   
2.1
   
47.0
Goodwill amortization
   
 
—  
 
   
.8
   
—  
   
—  
   
—  
 
   
—  
 
   
—  
   
.8
Exploration expenses
                                                
Dry holes
   
 
.2
 
   
19.8
   
—  
   
—  
   
3.8
 
   
3.8
 
   
—  
   
27.6
Geological and geophysical
   
 
—  
 
   
1.6
   
.1
   
—  
   
2.6
 
   
.5
 
   
—  
   
4.8
Other
   
 
1.1
 
   
.6
   
.3
   
—  
   
1.3
 
   
.3
 
   
—  
   
3.6
    
  
  
  
  
  
  
  
    
 
1.3
 
   
22.0
   
.4
   
—  
   
7.7
 
   
4.6
 
   
—  
   
36.0
Undeveloped lease amortization
   
 
2.1
 
   
3.5
   
—  
   
—  
   
—  
 
   
—  
 
   
—  
   
5.6
    
  
  
  
  
  
  
  
Total exploration expenses
   
 
3.4
 
   
25.5
   
.4
   
—  
   
7.7
 
   
4.6
 
   
—  
   
41.6
    
  
  
  
  
  
  
  
Selling and general expenses
   
 
2.9
 
   
3.0
   
.6
   
.1
   
—  
 
   
1.6
 
   
—  
   
8.2
Income tax provisions (benefits)
   
 
13.0
 
   
15.0
   
12.3
   
—  
   
—  
 
   
(.1
)
   
3.0
   
43.2
    
  
  
  
  
  
  
  
Results of operations (excluding
  corporate overhead and interest)
   
$
24.6
 
   
18.9
   
21.4
   
4.3
   
(7.8
)
   
(5.7
)
   
4.9
   
60.6
    
  
  
  
  
  
  
  
Six Months Ended June 30, 2002
                                                
Oil and gas sales, other operating revenues
   
$
76.4
 
   
259.7
   
84.5
   
13.5
   
—  
 
   
1.1
 
   
42.6
   
477.8
Production expenses
   
 
28.2
 
   
45.5
   
19.8
   
6.4
   
—  
 
   
—  
 
   
24.0
   
123.9
Depreciation, depletion and amortization
   
 
19.8
 
   
84.8
   
17.9
   
2.6
   
.5
 
   
.1
 
   
4.2
   
129.9
Exploration expenses
                                                
Dry holes
   
 
22.5
 
   
13.4
   
—  
   
—  
   
36.9
 
   
—  
 
   
—  
   
72.8
Geological and geophysical
   
 
3.3
 
   
9.1
   
—  
   
—  
   
.6
 
   
—  
 
   
—  
   
13.0
Other
   
 
2.2
 
   
1.0
   
.5
   
—  
   
2.1
 
   
(.1
)
   
—  
   
5.7
    
  
  
  
  
  
  
  
    
 
28.0
 
   
23.5
   
.5
   
—  
   
39.6
 
   
(.1
)
   
—  
   
91.5
Undeveloped lease amortization
   
 
5.2
 
   
7.1
   
—  
   
—  
   
—  
 
   
—  
 
   
—  
   
12.3
    
  
  
  
  
  
  
  
Total exploration expenses
   
 
33.2
 
   
30.6
   
.5
   
—  
   
39.6
 
   
(.1
)
   
—  
   
103.8
    
  
  
  
  
  
  
  
Selling and general expenses
   
 
6.1
 
   
6.9
   
1.6
   
.4
   
—  
 
   
2.6
 
   
.1
   
17.7
Income tax provisions (benefits)
   
 
(4.2
)
   
29.7
   
22.3
   
—  
   
—  
 
   
(.3
)
   
4.7
   
52.2
    
  
  
  
  
  
  
  
Results of operations (excluding
  corporate overhead and interest)
   
$
(6.7
)
   
62.2
   
22.4
   
4.1
   
(40.1
)
   
(1.2
)
   
9.6
   
50.3
    
  
  
  
  
  
  
  
Six Months Ended June 30, 2001
                                                
Oil and gas sales, other operating revenues
   
$
163.5
 
   
199.5
   
101.5
   
20.3
   
—  
 
   
.9
 
   
49.5
   
535.2
Production expenses
   
 
24.8
 
   
36.3
   
14.8
   
8.4
   
—  
 
   
—  
 
   
28.5
   
112.8
Depreciation, depletion and amortization
   
 
20.7
 
   
41.9
   
18.7
   
3.6
   
.2
 
   
.1
 
   
4.2
   
89.4
Goodwill amortization
   
 
—  
 
   
1.6
   
—  
   
—  
   
—  
 
   
—  
 
   
—  
   
1.6
Exploration expenses
                                                
Dry holes
   
 
15.7
 
   
23.2
   
.1
   
—  
   
3.8
 
   
3.8
 
   
—  
   
46.6
Geological and geophysical
   
 
3.7
 
   
9.0
   
.1
   
—  
   
2.9
 
   
.6
 
   
—  
   
16.3
Other
   
 
1.4
 
   
1.3
   
.5
   
—  
   
2.1
 
   
.6
 
   
—  
   
5.9
    
  
  
  
  
  
  
  
    
 
20.8
 
   
33.5
   
.7
   
—  
   
8.8
 
   
5.0
 
   
—  
   
68.8
Undeveloped lease amortization
   
 
4.1
 
   
6.7
   
—  
   
—  
   
—  
 
   
—  
 
   
—  
   
10.8
    
  
  
  
  
  
  
  
Total exploration expenses
   
 
24.9
 
   
40.2
   
.7
   
—  
   
8.8
 
   
5.0
 
   
—  
   
79.6
    
  
  
  
  
  
  
  
Selling and general expenses
   
 
6.7
 
   
5.1
   
1.2
   
.2
   
—  
 
   
3.0
 
   
—  
   
16.2
Income tax provisions (benefits)
   
 
30.7
 
   
32.8
   
24.6
   
—  
   
—  
 
   
(.2
)
   
6.5
   
94.4
    
  
  
  
  
  
  
  
Results of operations (excluding
  corporate overhead and interest)
   
$
55.7
 
   
41.6
   
41.5
   
8.1
   
(9.0
)
   
(7.0
)
   
10.3
   
141.2
    
  
  
  
  
  
  
  
 
 

17

 
PART II—OTHER INFORMATION
 
ITEM 1.    LEGAL PROCEEDINGS
 
In June 2000, the U.S. Government filed a lawsuit against Murphy Oil USA, Inc., the Company’s wholly-owned subsidiary, in federal court in Madison, Wisconsin, alleging violations of environmental laws at the Company’s Superior, Wisconsin refinery. The lawsuit was divided into liability and damage phases, and on August 1, 2001, the court ruled against the Company in the liability phase of the trial. Subsequent to the court ruling, the Company and the U.S. Government reached a tentative agreement that was filed with the federal court in January 2002. The settlement was approved by the court following a 30-day public comment period that expired March 7, 2002. According to the settlement agreement, the Company paid a civil penalty of $5.5 million in April 2002 and must implement specified environmental projects to resolve Clean Air Act violations. The Company had previously recorded a liability of $5.5 million to cover the liability.
 
In December 2000, two of the Company’s Canadian subsidiaries 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 acquired the lands after first inappropriately obtaining confidential and proprietary data belonging to the Company and its joint venturer. In January 2001, one of the defendants, 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 joint venturer at cost. In 2001, the remaining defendants, representing the remaining undivided 25% of the lands in question, filed a counterclaim against the Company’s two Canadian subsidiaries and one officer individually seeking compensatory damages of C$6.14 billion. The Company believes that the counterclaim is without merit and that the amount of damages sought is frivolous. While the litigation is in its preliminary stages 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.
 
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, 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.
 
ITEM 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
At the annual meeting of security holders on May 8, 2002, the directors proposed by management were elected with a tabulation of votes to the nearest share as shown below.
 
    
For
   
Withheld
George S. Dembroski
   
41,372,784
   
767,074
Claiborne P. Deming
   
41,581,176
   
558,682
H. Rodes Hart
   
41,432,020
   
707,838
Robert A. Hermes
   
41,584,917
   
554,941
Michael W. Murphy
   
41,475,856
   
664,002
R. Madison Murphy
   
41,580,019
   
559,839
William C. Nolan Jr.
   
41,265,346
   
874,512
William L. Rosoff
   
41,585,410
   
554,448
David J. H. Smith
   
41,644,766
   
495,092
Caroline G. Theus
   
41,474,582
   
665,276
 
The security holders approved the Company’s annual Incentive Compensation Plan and the performance criteria thereof by a vote of 41,414,183 shares in favor, 674,245 shares against and 51,430 shares not voted. Also the performance criteria for the Company’s Long-Term Incentive Plan was approved by a vote of 41,713,854 shares in favor, 309,312 shares against and 116,692 shares not voted. In addition, the earlier appointment by the Board of Directors of KPMG LLP as independent auditors for 2002 was approved, with 41,436,260 shares voted in favor, 661,329 shares voted in opposition and 42,269 shares not voted.

18

 
ITEM 6.    EXHIBITS AND REPORTS ON FORM 8-K
 
(a)
   
The Exhibit Index on page 20 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.
(b)
   
A report on Form 8-K was filed on April 26, 2002 that included the Company’s News Release, dated April 24, 2002, announcing the Company’s earnings and certain other financial information for the three-month period ended March 31, 2002.
(c)
   
A report on Form 8-K was filed on May 3, 2002 that included the Second Supplemental Indenture, dated May 2, 2002, between the Company and SunTrust Bank as Trustee (“the Trustee”).
 
 
 
 
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.
 
MURPHY OIL CORPORATION
  (Registrant)
 
By:
  
/s/    JOHN W. ECKART         
   
John W. Eckart, Controller
(Chief Accounting Officer and Duly
Authorized Officer)
 
August 2, 2002
(Date)
 

19

 
EXHIBIT INDEX
 
Exhibit
No.
       
Incorporated by Reference to
  3.1
  
Certificate of Incorporation of Murphy Oil Corporation
as amended, effective May 17, 2001
   
Exhibit 3.1 of Murphy’s Form 10-Q report for the quarterly period ended June 30, 2001
  3.2
  
By-Laws of Murphy Oil Corporation as amended effective May 8, 2002
   
Exhibit 3.2 filed herewith
  4   
  
Instruments Defining the Rights of Security Holders. Murphy is party to several long-term debt instruments in addition to the one in Exhibit 4.1, none of which authorizes securities exceeding 10% of the total consolidated assets of Murphy and its subsidiaries. Pursuant to Regulation S-K, item 601(b), paragraph 4(iii)(A), Murphy agrees to furnish a copy of each such instrument to the Securities and Exchange Commission upon request
     
  4.1
  
Form of Second Supplemental Indenture between Murphy Oil Corporation and SunTrust Bank, as Trustee
   
Exhibit 4.1 of Murphy’s Form 8-K report filed May 3, 2002 under the Securities Exchange Act of 1934
  4.2
  
Form of Indenture and Form of Supplemental Indenture between Murphy Oil Corporation and SunTrust Bank, as Trustee
   
Exhibits 4.1 and 4.2 of Murphy’s Form 8-K report filed April 29, 1999 under the Securities Exchange Act of 1934
  4.3
  
Rights Agreement dated as of December 6, 1989 between Murphy Oil Corporation and Harris Trust Company of New York, as Rights Agent
   
Exhibit 4.3 of Murphy’s Form 10-K report for the year ended December 31, 1999
  4.4
  
Amendment No. 1 dated as of April 6, 1998 to Rights Agreement dated as of December 6, 1989 between Murphy Oil Corporation and Harris Trust Company of New York, as Rights Agent
   
Exhibit 3 of Murphy’s Form 8-A/A, Amendment No. 1, filed April 14, 1998 under the Securities Exchange Act of 1934
  4.5
  
Amendment No. 2 dated as of April 15, 1999 to Rights Agreement dated as of December 6, 1989 between Murphy Oil Corporation and Harris Trust Company of New York, as Rights Agent
   
Exhibit 4 of Murphy’s Form 8-A/A, Amendment No. 2, filed April 19, 1999 under the Securities Exchange Act of 1934
10.1
  
1992 Stock Incentive Plan as amended May 14, 1997
   
Exhibit 10.2 of Murphy’s Form 10-Q report for the quarterly period ended June 30, 1997
10.2
  
Employee Stock Purchase Plan as amended May 10, 2000
   
Exhibit 99.01 of Murphy’s Form S-8 registration statement filed August 4, 2000 under the Securities Act of 1933
99.1
  
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
   
Exhibit 99.1 filed herewith
99.2
  
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
   
Exhibit 99.2 filed herewith
 
Exhibits other than those listed above have been omitted since they are either not required or not applicable.

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