Murphy Oil - 10-Q quarterly report FY

 

 

 

 

 

 

 

 

 

 

 

 

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)

 

 

 

 

Number of shares of Common Stock, $1.00 par value, outstanding at June 30, 2002, was 45,816,063.

 

 

 

 

 

		(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.

 

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		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.

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		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.

 

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		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

 

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.

 

 

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.

 

 

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.

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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.

 

 

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.

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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.

 

 

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.

 

 

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.

 

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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.

 

 

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	)

 

 

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.

 

 

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.

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		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

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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.

 

 

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

 

 

 

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

 

 

 

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

13

 

 

 

 

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

 

 

 

 

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.

 

 

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

 

 

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

 

 

 

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.

 

 

This Form 10-Q report contains statements of the Company’s expectations, intentions, plans and beliefs that are forward-looking and are dependent on certain events, risks and uncertainties that may be outside of the Company’s control. These forward-looking statements are made in reliance upon the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Actual results and developments could differ materially from those expressed or implied by such statements due to a number of factors including those described in the context of such forward-looking statements as well as those contained in the Company’s January 15, 1997 Form 8-K report on file with the U.S. Securities and Exchange Commission.

 

 

The Company 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

 

 

		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