Edgar Filing: MURPHY OIL CORP /DE

Form 10-Q

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 March 31, 2006

¨	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		71-0361522
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

200 Peach Street P.O. Box 7000, El Dorado, Arkansas		71731-7000
(Address of principal executive offices)		(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. x Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and larger accelerated filer” in Rule 12b-2 of the Exchange act. (Check one):

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes x No

Number of shares of Common Stock, $1.00 par value, outstanding at March 31, 2006 was 186,635,299.

MURPHY OIL CORPORATION

TABLE OF CONTENTS


		Page
Part I – Financial Information

Item 1. Financial Statements

Consolidated Balance Sheets		2
Consolidated Statements of Income		3
Consolidated Statements of Comprehensive Income		4
Consolidated Statements of Cash Flows		5
Consolidated Statements of Stockholders’ Equity		6
Notes to Consolidated Financial Statements		7

Item 2. Management’s Discussion and Analysis of Results of Operations and Financial Condition		17

Item 3. Quantitative and Qualitative Disclosures About Market Risk		24

Item 4. Controls and Procedures		24

Part II – Other Information

Item 1. Legal Proceedings		25

Item 1A. Risk Factors		26

Item 6. Exhibits and Reports on Form 8-K		26

Signature		27

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)


	(Unaudited)
	March 31, 2006			December 31, 2005
ASSETS
Current assets
Cash and cash equivalents	$	480,905		585,333
Accounts receivable, less allowance for doubtful accounts of $14,625 in 2006 and $14,508 in 2005		988,319		865,155
Inventories, at lower of cost or market
Crude oil and blend stocks		52,279		83,265
Finished products		128,081		146,753
Materials and supplies		86,163		84,937
Prepaid expenses		76,885		33,239
Deferred income taxes		39,654		40,264

Total current assets		1,852,286		1,838,946

Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $2,558,809 in 2006 and $2,459,022 in 2005		4,494,829		4,374,229
Goodwill, net		43,960		44,206
Deferred charges and other assets		116,357		111,130

Total assets	$	6,507,432		6,368,511

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	4,456		4,490
Accounts payable and accrued liabilities		1,208,532		1,176,634
Income taxes payable		111,853		105,884

Total current liabilities		1,324,841		1,287,008

Notes payable		597,975		597,926
Nonrecourse debt of a subsidiary		11,583		11,648
Deferred income taxes		607,057		614,091
Asset retirement obligations		178,102		176,823
Accrued major repair costs		56,820		55,350
Deferred credits and other liabilities		165,079		164,675

Stockholders’ equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued		—		—
Common Stock, par $1.00, authorized 450,000,000 shares, issued 186,828,618 shares		186,829		186,829
Capital in excess of par value		420,286		437,963
Retained earnings		2,837,153		2,744,274
Accumulated other comprehensive income		126,746		131,324
Unamortized restricted stock awards		—		(16,410	)
Treasury stock, 193,319 shares of Common Stock in 2006 and 881,940 shares in 2005, at cost		(5,039	)	(22,990	)

Total stockholders’ equity		3,565,975		3,460,990

Total liabilities and stockholders’ equity	$	6,507,432		6,368,511

See Notes to Consolidated Financial Statements, page 7.

The Exhibit Index is on page 28.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

(Thousands of dollars, except per share amounts)


	Three Months Ended March 31,
	2006			2005
REVENUES
Sales and other operating revenues	$	2,987,119		2,404,001
Gain (loss) on sale of assets		(1,264	)	311
Interest and other income		5,408		10,560

Total revenues		2,991,263		2,414,872

COSTS AND EXPENSES
Crude oil and product purchases		2,307,496		1,789,544
Operating expenses		232,164		203,643
Exploration expenses, including undeveloped lease amortization		63,163		70,295
Selling and general expenses		40,472		36,305
Depreciation, depletion and amortization		97,358		104,754
Net costs associated with hurricanes		35,722		—
Accretion of asset retirement obligations		2,500		2,639
Interest expense		10,563		12,036
Interest capitalized		(9,589	)	(7,567	)

Total costs and expenses		2,779,849		2,211,649

Income before income taxes		211,414		203,223
Income tax expense		97,542		90,070

NET INCOME	$	113,872		113,153

INCOME PER COMMON SHARE
NET INCOME – BASIC	$	.61		.61	*

NET INCOME – DILUTED	$	.60		.60	*

Average Common shares outstanding – basic		185,713,673		184,248,272	*
Average Common shares outstanding – diluted		188,636,321		187,806,028	*

*	Income Per Common Share and Average Common Shares Outstanding for 2005 above and throughout this Form 10-Q have been adjusted to reflect the two-for-one stock split effective June 3, 2005.

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

(Thousands of dollars)


	Three Months Ended March 31,
	2006			2005
Net income	$	113,872		113,153

Other comprehensive income (loss), net of tax
Cash flow hedges
Net derivative losses		(11,778	)	(13,967	)
Reclassification to income		8,547		(289	)

Total cash flow hedges		(3,231	)	(14,256	)
Minimum pension liability adjustment		13		—
Net loss from foreign currency translation		(1,360	)	(851	)

COMPREHENSIVE INCOME	$	109,294		98,046

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)


	Three Months Ended March 31,
	2006			2005
OPERATING ACTIVITIES
Net income	$	113,872		113,153
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		97,358		104,754
Provisions for major repairs		7,665		7,164
Expenditures for major repairs and asset retirements		(7,357	)	(10,095	)
Dry hole costs		37,081		51,282
Amortization of undeveloped leases		5,430		6,982
Accretion of asset retirement obligations		2,500		2,639
Deferred and noncurrent income tax charges		496		119
Pretax (gain) loss from disposition of assets		1,264		(311	)
Net increase in noncash operating working capital		(79,901	)	(57,296	)
Other operating activities, net		5,382		(11,769	)

Net cash provided by operating activities		183,790		206,622

INVESTING ACTIVITIES
Property additions and dry hole costs		(279,474	)	(259,328	)
Proceeds from sales of assets		4,732		583
Proceeds from maturities of marketable securities		–		17,892
Other – net		(2,738	)	(276	)

Net cash required by investing activities		(277,480	)	(241,129	)

FINANCING ACTIVITIES
Decrease in notes payable		(11	)	(9,640	)
Proceeds from exercise of stock options and employee stock purchase plans		6,743		337
Excess tax benefits related to exercise of stock options		3,792		–
Cash dividends paid		(20,993	)	(20,748	)

Net cash used in financing activities		(10,469	)	(30,051	)

Effect of exchange rate changes on cash and cash equivalents		(269	)	(7,103	)

Net decrease in cash and cash equivalents		(104,428	)	(71,661	)
Cash and cash equivalents at January 1		585,333		535,525

Cash and cash equivalents at March 31	$	480,905		463,864

SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid	$	126,046		172,971

Interest capitalized in excess of amounts paid		(9,353	)	(6,152	)

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

(Thousands of dollars)


	Three Months Ended March 31,
	2006			2005
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued		—		—

Common Stock – par $1.00, authorized 450,000,000 shares at March 31, 2006 and 200,000,000 shares at March 31, 2005, issued 186,828,618 shares at March 31, 2006 and 94,613,379 shares at March 31, 2005
Balance at beginning and end of period	$	186,829		94,613

Capital in Excess of Par Value
Balance at beginning of period		437,963		511,045
Exercise of stock options, including income tax benefits		1,016		—
Restricted stock transactions and other		(7,433	)	14,502
Amortization, forfeitures and other		5,150		—
Sale of stock under employee stock purchase plans		—		216
Reclassification from Unamortized Restricted Stock Awards upon adoption of SFAS No. 123 R		(16,410	)	—

Balance at end period		420,286		525,763

Retained Earnings
Balance at beginning of period		2,744,274		1,981,020
Net income for the period		113,872		113,153
Cash dividends		(20,993	)	(20,748	)

Balance at end of period		2,837,153		2,073,425

Accumulated Other Comprehensive Income
Balance at beginning of period		131,324		134,509
Foreign currency translation losses, net of income taxes		(1,360	)	(851	)
Cash flow hedging losses, net of income taxes		(3,231	)	(14,256	)
Minimum pension liability adjustment		13		—

Balance at end of period		126,746		119,402

Unamortized Restricted Stock Awards
Balance at beginning of period		(16,410	)	(4,738	)
Reclassification to Capital in Excess of Par Value upon adoption of SFAS No. 123 R		16,410		—
Stock awards		—		(16,344	)
Amortization, forfeitures and other		—		(1,051	)

Balance at end of period		—		(22,133	)

Treasury Stock
Balance at beginning of period		(22,990	)	(67,293	)
Exercise of stock options		10,531		—
Sale of stock under employee stock purchase plans		—		121
Awarded restricted stock, net of forfeitures		7,420		4,659

Balance at end of period		(5,039	)	(62,513	)

Total Stockholders’ Equity	$	3,565,975		2,728,557

See notes to consolidated financial statements, page 7.

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 2 through 6 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, 2005. In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at March 31, 2006, and the results of operations and cash flows for the three-month periods ended March 31, 2006 and 2005, in conformity with accounting principles generally accepted in the United States. In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the United States, management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.

Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2005 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three months ended March 31, 2006 are not necessarily indicative of future results.

Note B – Property, Plant and Equipment

The Financial Accounting Standards Board (FASB) has issued FASB Staff Position (FSP) 19-1 which applies to companies that use the successful efforts method of accounting, that clarifies that exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The guidance in this FSP was applied on a prospective basis beginning in April 2005 to existing and newly-capitalized exploratory well costs. The adoption of this FSP had no effect on the Company’s 2005 net income or financial condition.

At March 31, 2006, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $335.7 million. The following table reflects the net changes in capitalized exploratory well costs during the three-month periods ended March 31, 2006 and 2005.


(Thousands of dollars)	2006		2005
Beginning balance at January 1	$	275,256	106,105
Additions pending the determination of proved reserves		60,470	80,426

Balance at March 31	$	335,726	186,531

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling.


(Thousands of dollars)	2006		2005
Exploratory well costs capitalized for one year or less	$	175,008	174,382
Capitalized exploratory well costs capitalized for more than one year		160,718	12,149

Balance at March 31	$	335,726	186,531

Number of projects that have exploratory well costs that have been capitalized for more than one year		12	1

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C – Employee and Retiree Benefit Plans

The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors’ plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.

The table that follows provides the components of net periodic benefit expense for the three-month periods ended March 31, 2006 and 2005.


	Pension Benefits					Postretirement Benefits
(Thousands of dollars)	2006			2005		2006		2005
Service cost	$	2,659		2,108		566		446
Interest cost		5,328		4,355		1,006		841
Expected return on plan assets		(5,031	)	(4,141	)	—		—
Amortization of prior service cost		367		64		(69	)	(64	)
Amortization of transitional asset		(156	)	(44	)	—		—
Recognized actuarial loss		1,527		1,113		446		324

Net periodic benefit expense	$	4,694		3,455		1,949		1,547

Murphy previously disclosed in its financial statements for the year ended December 31, 2005, that it expected to contribute $7.5 million to its defined benefit pension plans and $3.6 million to its postretirement benefits plan during 2006. During the three-month period ended March 31, 2006, the Company made contributions of $2.1 million and remaining funding for the 2006 year for the Company’s domestic and foreign defined benefit pension and postretirement plans is anticipated to be $9.0 million.

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) provides prescription drug coverage under Medicare beginning in 2006. Generally, companies that provide qualifying prescription drug coverage that is deemed actuarially equivalent to medicare coverage for retirees aged 65 and above will be eligible to receive a federal subsidy equal to 28% of drug costs between $250 and $5,000 per annum for each covered individual that does not elect to receive coverage under the new prescription drug Medicare Part D. The Company currently provides prescription drug coverage to qualifying retirees under its retiree medical plan. The Company recognized estimated benefits of $0.4 million related to the Act in each of the three-month periods ended March 31, 2006 and 2005.

Note D – Incentive Plans

The FASB issued Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), Share Based Payment (SFAS No. 123 R), which replaced SFAS No. 123, Accounting for Stock-Based Compensation (SFAS No. 123), and superseded APB Opinion No. 25, Accounting for Stock Issued to Employees (APB No. 25). SFAS No. 123 R requires that the cost resulting from all share-based payment transactions be recognized as an expense in the financial statements using a fair value-based measurement method over the periods that the awards vest. The Company adopted SFAS No. 123 R as of January 1, 2006. Prior to 2006, the Company used APB No. 25 to account for stock-based compensation.

The Company’s 1992 Stock Incentive Plan (1992 Plan) authorized the Executive Compensation Committee (the Committee) to make annual grants of the Company’s Common Stock to executives and other key employees in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), and/or restricted stock. Annual grants may not exceed 1% of shares outstanding at the end of the preceding year; allowed shares not granted may be granted in future years. In addition, the Stock Plan for Non-Employee Directors (2003 Director Plan) permits the issuance of restricted stock and stock options or a combination thereof to the Company’s Directors. Compensation costs charged against income for stock-based plans during the three-month periods ended March 31, 2006 and 2005 was $6.5 million and $2.8 million, respectively. The income tax benefits recognized in the income statement for share-based compensation arrangements was $2.3 million and $1.0 million, respectively.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – Incentive Plans (Contd.)

As of March 31, 2006, there was $21.6 million in compensation costs to be expensed in future periods related to unvested share-based compensation arrangements granted by the Company. That cost is expected to be recognized over a period of approximately three years. Cash received from options exercised under all share-based payment arrangements for the three-month periods ended March 31, 2006 and 2005 was $6.7 million and $0.3 million, respectively. The actual income tax benefit realized for the tax deductions from option exercise of the share-based payment arrangements totaled $4.4 million and less than $0.1 million for the three-month periods ended March 31, 2006 and 2005, respectively.

The Company has a history of issuing Treasury shares to satisfy share option exercises; however due to the lack of remaining Treasury shares, in the future it expects to issue shares from authorized but unissued common stock to satisfy share option exercises.

STOCK OPTIONS – The Committee fixes the option price of each option granted at no less than fair market value (FMV) on the date of the grant and fixes the option term at no more than 10 years from such date. Each option granted to date under the 1992 Plan has had a term of 7 to 10 years, has been nonqualified, and has had an option price equal to or higher than FMV at date of grant. Under the 1992 Plan, one-half of each grant is exercisable after two years and the remainder after three years. Under the 2003 Director Plan, one-third of each grant is exercisable after each of the first three years.

Prior to adopting SFAS No. 123 R, the Company used the intrinsic-value based method of accounting as prescribed by APB No. 25 and related interpretations to account for its stock options. Under this method, the Company accrued costs of restricted stock and any stock option deemed to be variable in nature over the vesting/performance period and adjusted such costs for changes in the fair market value of Common Stock. No compensation expense was recorded for fixed stock options since all option prices were equal to or greater than the fair market value of the Company’s stock on the date of grant. Had the Company recorded compensation expense for stock options as prescribed by SFAS No. 123, net income and earnings per share for the three-month period ended March 31, 2005, would have been the pro forma amounts shown in the following table.


(Thousands of dollars except per share data)	2005
Net income – As reported	$	113,153
Restricted stock compensation expense included in income, net of tax		1,161
Total stock-based compensation expense using fair value method for all awards, net of tax		(2,601	)

Net income – Pro forma	$	111,713

Net income per share – As reported, basic	$	.61
Pro forma, basic		.61
As reported, diluted		.60
Pro forma, diluted		.59

Under SFAS 123 R, the fair value of each option award is estimated on the date of grant using the Black-Scholes pricing model that uses the assumptions noted in the following table. Expected volatility is based on historical volatility of the Company’s stock and implied volatility on publicly traded at-the-money options on the Company’s stock. The Company uses historical data to estimate option exercise patterns within the valuation model. The expected term of the options granted is derived from historical behavior and considers certain groups of employees exhibiting different behavior. The risk-free rate for periods within the expected term of the option is based on the U.S. Treasury yield curve in effect at the time of grant.


	2006			2005
Fair value per option grant	$	17.53		11.79
Assumptions
Dividend yield		.90	%	1.25	%
Expected volatility		30.00	%	26.00	%
Risk-free interest rate		4.42	%	3.74	%
Expected life		4.75	yrs.	5.00	yrs.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – Incentive Plans (Contd.)

Changes in stock options outstanding during the three-month periods ended March 31, 2006 and 2005 are presented in the following table.


	2006				2005
	Number of Shares		Average Exercise Price		Number of Shares	Average Exercise Price
Outstanding at January 1	8,414,637		$	21.92	9,037,580	$	18.47
Granted at fair market value	787,500			57.32	935,000		45.23
Exercised	(403,985	)		16.69	—		—

Outstanding at March 31	8,798,152		$	25.33	9,972,580	$	20.97

Exercisable at March 31	6,537,998		$	18.22	7,121,620	$	16.33

The total intrinsic value of stock options exercised during the three-month period ended March 31, 2006 was $15.8 million. No stock options were exercised during the three-month period ended March 31, 2005.

Additional information about stock options outstanding at March 31, 2006 and 2005 is shown below.


	Options Outstanding						Options Exercisable
	No. of Shares	Avg. Life in Years	Avg. Price		Aggregate Intrinsic Value ($000)		No. of Shares	Avg. Life in Years	Avg. Price		Aggregate Intrinsic Value ($000)
March 31, 2006	8,798,152	5.5	$	25.33	$	221,410	6,537,998	4.6	$	18.22	$	206,623
March 31, 2005	9,972,580	6.2		20.97		283,150	7,721,620	4.1		16.33		235,293

SAR – SAR may be granted in conjunction with or independent of stock options; if granted, the Committee would determine when SAR may be exercised and the price. No SAR have been granted.

PERFORMANCE-BASED RESTRICTED STOCK – Shares of restricted stock were granted under the Plan in certain years. Each grant will vest if the Company achieves specific objectives based on market conditions at the end of the three-year performance period. Additional shares may be awarded if objectives are exceeded, but some or all shares may be forfeited if objectives are not met. During the performance period, a grantee receives dividends and may vote these shares, but shares are subject to transfer restrictions and are subject to forfeiture if a grantee terminates. In the event that the shares vest, the Company shall reimburse a grantee up to 50% of the fair market value of the restricted stock for personal income tax liability. Changes in performance-based restricted stock outstanding during the three-month periods ended March 31, 2006 and 2005 are presented in the following table.


(Number of shares)	2006		2005
Balance at January 1	478,445		157,000
Granted	265,750		336,000
Forfeited	(500	)	(14,555	)

Balance at March 31	743,695		478,445

The fair value of the performance shares granted in 2006 was estimated on the date of grant using a Monte Carlo valuation model. Prior grants were based on the fair market value of the Company’s stock on the date of grant. If performance goals are not met, shares will not be awarded, but recognized compensation cost would not be reversed.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – Incentive Plans (Contd.)

Expected volatility was based on daily historical volatility of the Company and a peer group average over a three year period. The risk-free interest rate is based on the yield curve of 3-year U.S. Treasury bonds and the stock beta was calculated using three years of historical Murphy and a peer group average of daily stock data. The assumptions used in the valuation of the performance awards granted in 2006 are presented in the following table.


Fair value per share at grant date	$	37.33
Assumptions
Expected volatility		26.30	%
Risk-free interest rate		4.49	%
Stock beta		.955
Expected life		3.00	yrs.

The fair value of the Company’s stock on the date of grant for the 2005 awards was $45.23 per share.

TIME-BASED RESTRICTED STOCK – Shares of restricted stock were granted to the Company’s Directors under the 2003 Director Plan and vest on the third anniversary of the date of grant. The fair value of these awards was estimated based on the fair market value of the Company’s stock on the date of grant, which was $57.32 per share in 2006 and $45.23 per share in 2005. Changes in time-based restricted stock outstanding for each of the periods are presented in the following table.


(Number of shares)	2006	2005
Balance at January 1	35,574	12,624
Granted	19,386	22,950

Balance at March 31	54,960	35,574

EMPLOYEE STOCK PURCHASE PLAN (ESPP) – The Company has an ESPP under which 600,000 shares of the Company’s Common Stock can be purchased by eligible U.S. and Canadian employees. Each quarter, an eligible employee may elect to withhold up to 10% of his or her salary to purchase shares of the Company’s stock at the end of the quarter at a price equal to 90% of the fair value of the stock as of the first day of the quarter. The participating employee retains an options to cease participation and withdraw withheld funds up to the end of the quarter. The ESPP will terminate on the earlier of the date that employees have purchased all 600,000 shares or June 30, 2007. Employee stock purchases under the ESPP were 6,718 shares at an average price of $48.59 per share in the three-month period ended March 31, 2006 and 9,304 shares at $36.21 per share in the same period of 2005. Compensation costs related to the ESPP are estimated based on the value of the 10% discount and the fair value of the option that provides for the refund of participant withholdings. At March 31, 2006, 142,767 shares remained available for sale under the ESPP. The fair value per share of the ESPP was $7.89 for the three-month period ended March 31, 2006.

SAVINGS-RELATED SHARE OPTION PLAN (SAYE) – One of the Company’s U.K. subsidiaries provides a plan that allows shares of the Company’s Common stock to be purchased by eligible employees using payroll withholdings. An eligible employee may elect to withhold from £5 to £250 per month to purchase shares of the Company stock at a price equal to 90% of the fair value of the stock as of the date of grant. The SAYE plan has a term of three years, and employee withholdings are fixed over the life of the plan. At the end of the term of the SAYE plan an employee has six months to decide whether to exercise their option to purchase shares of Company stock or receive a repayment of withholdings plus credited interest. Compensation costs related to the SAYE plan are estimated based on the value of the 10% discount and the fair value of the option that allows the employee to receive a repayment of withholdings plus credited interest. The fair value per share of the SAYE Plans terminating in May 2007 and December 2009 are $11.64 and $19.57, respectively.

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 months ended March 31, 2006 and 2005. The following table reconciles the weighted-average shares outstanding used for these computations.


	Three Months Ended March 31
(Weighted-average shares)	2006	2005
Basic method	185,713,673	184,248,272
Dilutive stock options	2,922,648	3,557,756

Diluted method	188,636,321	187,806,028

Options to purchase 1,525,625 shares of common stock at a weighted average share price of $49.91 were outstanding during the first quarter of 2006 but were not included in the computation of diluted EPS because the incremental shares from assumed conversion were antidilutive. There were no antidilutive options for the period ended March 31, 2005.

Note F – Financial Instruments and Risk Management

Murphy utilizes derivative instruments to manage certain risks related to interest rates, commodity prices, and foreign currency exchange rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges.

•

Natural Gas Fuel Price Risks – The Company purchases natural gas as fuel at its Meraux, Louisiana and Superior, Wisconsin refineries, 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 at Meraux in 2006 by entering into financial contracts known as natural gas swaps with a remaining notional volume as of March 31, 2006 of 0.5 million MMBTU (million British Thermal Units). Under the natural gas swaps, the Company pays a fixed rate averaging $3.35 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 requirements and to Murphy’s natural gas swaps. The control system involves using analytical techniques, including various correlations of natural gas purchase prices to future 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 AOCI and is subsequently reclassified into Crude Oil and Product Purchases in the income statements in the periods in which the hedged natural gas fuel purchases affect earnings. During the three-month periods ended March 31, 2006 and 2005, the Company received approximately $1.0 million and $1.1 million, respectively, for maturing swap agreements. For the three-month periods ended March 31, 2006 and 2005, the income effect from cash flow hedging ineffectiveness for these contracts was insignificant.

•

Crude Oil Sales Price Risks – The sales price of crude oil 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 its Canadian heavy oil production during 2006 by entering into forward sale contracts covering a notional volume of approximately 4,000 barrels per day in 2006. The Company will pay the average of the posted price for blended heavy oil at the Hardisty terminal in Canada for each month and receive at that location a fixed price of $25.23 per barrel in 2006. Murphy has a risk management control system to monitor crude oil price risk attributable both to forecasted crude oil sales prices and to Murphy’s hedging instruments. The control system involves using analytical techniques, including various correlations of crude oil sales prices to future prices, to estimate the impact of changes in crude oil prices on Murphy’s cash flows from the sale of heavy crude oil. The fair values of the effective portions of the crude oil hedges and changes thereto are deferred in AOCI and are subsequently reclassified into Sales and Other Operating Revenues in the income statement in the periods in which the hedged crude oil sales affect earnings. During the three-month periods ended March 31, 2006 and 2005, cash flow hedging ineffectiveness relating to the crude oil sales contracts was insignificant. During the three-month periods ended March 31, 2006 and 2005 the Company paid approximately $12.9 million and $0.5 million, respectively for settlement of maturing forward sale contracts. The fair value of the crude oil sales contracts are based on the average fixed price of the instruments and the published NYMEX index futures price or crude oil price quotes from counterparties.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note F – Financial Instruments and Risk Management (Contd.)

During the next nine months, the Company expects to reclassify approximately $16.7 million in net after-tax losses from AOCI into earnings as the forecasted transactions covered by hedging instruments actually occur. All forecasted transactions currently being hedged are expected to occur by December 31, 2006.

Note G – Accumulated Other Comprehensive Income

The components of Accumulated Other Comprehensive Income (AOCI) on the Consolidated Balance Sheets at March 31, 2006 and December 31, 2005 are presented in the following table.


(Thousands of dollars)	March 31, 2006			Dec. 31, 2005
Foreign currency translation, net of tax	$	184,362		185,722
Cash flow hedging, net of tax		(16,690	)	(13,459	)
Minimum pension liability, net of tax		(40,926	)	(40,939	)

Accumulated other comprehensive income	$	126,746		131,324

The effect of SFAS Nos. 133/138, Accounting for Derivative Investments and Hedging Activities, decreased AOCI for the three months ended March 31, 2006 by $3.2 million, net of $1.9 million in income taxes, and hedging ineffectiveness was not significant. Derivative instruments decreased AOCI for the three months ended March 31, 2005 by $14.3 million, net of $5.9 million in income taxes, and hedging ineffectiveness was not significant. The AOCI decrease in the first quarter 2005 was primarily related to the change in fair value of blended heavy oil forward sales contracts described in Note F.

Note H – Hurricane and Insurance Related Matters

In 2006, the Company recorded pretax expenses, net of anticipated insurance recoveries, of $35.7 million associated with hurricanes that occurred in the United States in 2005, including $34.8 million at the Meraux refinery. The components of these refinery costs included $13.0 million for repair costs not expected to be recovered due to certain coverage limits for the Company’s insurance policies, $4.4 million for incremental insurance costs, $3.4 million for other uninsured incremental expenses incurred, and $14.0 million for depreciation and salaries for the temporarily idled refinery. The costs are reported in Net Costs Associated with Hurricanes in the Consolidated Statements of Income. The Company anticipates that Meraux will record additional unrecoverable repair costs of approximately $37 million related to Hurricane Katrina in the second quarter 2006. See Note I for additional information regarding environmental and other contingencies relating to Hurricane Katrina. Total accounts receivable from insurers for hurricane-related matters was $163.4 million at March 31, 2006.

The Company maintains insurance coverage related to losses of production and profits for occurrences such as storms, fires and other issues. During 2006, the Company received insurance proceeds of $15.7 million related to loss of production in the Gulf of Mexico associated with Hurricane Katrina in 2005. This amount was recorded in Sales and Other Operating Revenues in the respective Consolidated Statement of Income.

Note I – Environmental and Other Contingencies

The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax increases and retroactive tax claims; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Because governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences, and may be taken in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – Environmental and Other Contingencies (Contd.)

In addition to being subject to numerous laws and regulations intended to protect the environment and/or impose remedial obligations, the Company is also involved in personal injury and property damage claims, allegedly caused by exposure to or by the release or disposal of materials manufactured or used in the Company’s operations. The Company operates or has previously operated certain sites and facilities, including three refineries, five terminals, and approximately 60 service stations for which known or potential obligations for environmental remediation exist. In addition the Company operates or has operated numerous oil and gas fields that may require some form of remediation, which is generally provided for by the Company’s asset retirement obligation.

The Company’s liability for remedial obligations includes certain amounts that are based on anticipated regulatory approval for proposed remediation of former refinery waste sites. Although regulatory authorities may require more costly alternatives than the proposed processes, the cost of such potential alternative processes is not expected to exceed the accrued liability by a material amount.

The U.S. Environmental Protection Agency (EPA) currently considers the Company a Potentially Responsible Party (PRP) at two Superfund sites. The potential total cost to all parties to perform necessary remedial work at these sites may be substantial. Based on currently available information, the Company believes that it is a de minimis party as to ultimate responsibility at both Superfund sites. The Company has not recorded a liability for remedial costs on Superfund sites. The Company could be required to bear a pro rata share of costs attributable to nonparticipating PRPs or could be assigned additional responsibility for remediation at the two sites or other Superfund sites. The Company believes that its share of the ultimate costs to clean-up the two Superfund sites will be immaterial and will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.

On September 9, 2005, a class action lawsuit was filed in federal court in the Eastern District of Louisiana seeking unspecified damages to the class comprised of residents of St. Bernard Parish caused by a release of crude oil at Murphy Oil USA, Inc.’s (a wholly-owned subsidiary of Murphy Oil Corporation) Meraux, Louisiana, refinery as a result of flooding damage to a crude oil storage tank following Hurricane Katrina. Since then additional class action lawsuits have been filed in the same court against Murphy Oil USA, Inc. and/or Murphy Oil Corporation also seeking unspecified damages related to the crude oil release. The suits have been consolidated into a single action in the U.S. District Court for the Eastern District of Louisiana, which held a class certification hearing on January 12-13, 2006. The Court certified the class on January 30, 2006 and scheduled a trial as to liability in August 2006. The Company’s appeal of the class certification ruling was denied by the U.S. Fifth Circuit Court of Appeals on March 20, 2006. The Company believes that insurance coverage exists for this release and it does not expect to incur significant costs associated with the class action lawsuits. Accordingly, the Company believes that the ultimate resolution of these class action lawsuits will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

On June 10, 2003, a fire severely damaged the Residual Oil Supercritical Extraction (ROSE) unit at the Company’s Meraux, Louisiana refinery. The ROSE unit recovers feedstock from the heavy fuel oil stream for conversion into gasoline and diesel. Subsequent to the fire, numerous class action lawsuits have been filed seeking damages for area residents. All the lawsuits have been administratively consolidated into a single legal action in St. Bernard Parish, Louisiana, except for one such action which was filed in federal court. Additionally, individual residents of Orleans Parish, Louisiana, have filed an action in that venue. On May 5, 2004, plaintiffs in the consolidated action in St. Bernard Parish amended their petition to include a direct action against certain of the Company’s liability insurers. In responding to this direct action, one of the Company’s insurers, AEGIS, has raised lack of coverage as a defense. The Company believes that this contention lacks merit and has been advised by counsel that the applicable policy does provide coverage for the underlying incident. Because the Company believes that insurance coverage exists for this matter, it does not expect to incur any significant costs associated with the class action lawsuits. Accordingly, the Company continues to believe that the ultimate resolution of the June 2003 ROSE fire litigation will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – Environmental and Other Contingencies (Contd.)

In December 2000, two of the Company’s Canadian subsidiaries, Murphy Oil Company Ltd. (MOCL) and Murphy Canada Exploration Company (MCEC) as plaintiffs filed an action in the Court of Queen’s Bench of Alberta seeking a constructive trust over oil and gas leasehold rights to Crown lands in British Columbia. The suit alleges that the defendants, The Predator Corporation Ltd. and Predator Energies Partnership (collectively Predator) and Ricks Nova Scotia Co. (Ricks), acquired the lands after first inappropriately obtaining confidential and proprietary data belonging to the Company and its partner. In January 2001, Ricks, representing an undivided 75% interest in the lands in question, settled its portion of the litigation by conveying its interest to the Company and its partner at cost. In 2001, Predator, representing the remaining undivided 25% of the lands in question, filed a counterclaim against MOCL and MCEC and MOCL’s President individually seeking compensatory damages of C$3.61 billion. In September 2004 the court summarily dismissed all claims against MOCL’s president and all but C$356 million of the counterclaim against the Company. On February 28, 2006, the Court of Appeals ruled in favor of the Company and affirmed the dismissal order. The Company believes that the counterclaim is without merit, that the amount of damages sought is frivolous and the likelihood of a material loss to the Company is remote. A trial concerning the 25% disputed interest and any remaining issues began April 24, 2006. While no assurance can be given about the outcome, the Company does not believe that the ultimate resolution of this suit will have a material adverse effect on its net income, financial condition or liquidity in a future period. In the unlikely event that Predator were to prevail in its counterclaim for an amount approximating the damages sought, the result would have a material adverse effect on the Company’s net income, financial condition and liquidity.

Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide financial guarantees or letters of credit that may be drawn upon if the Company fails to perform under those contracts. At March 31, 2006, the Company had contingent liabilities of $8.5 million under a financial guarantee and $54.6 million on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to these letters of credit because it is believed that the likelihood of having these drawn is remote.

Note J – Business Segments


	Total Assets at March 31, 2006		Three Mos. Ended March 31, 2006				Three Mos. Ended March 31, 2005
(Millions of dollars)	Total Assets at March 31, 2006		External Revenues	Interseg. Revenues	Income (Loss)		External Revenues	Interseg. Revenues	Income (Loss)
Exploration and production*
United States	$	931.0	197.9	—	86.4		182.7	—	61.9
Canada		1,584.8	177.8	15.1	68.0		144.6	11.0	55.4
United Kingdom		196.3	52.8	—	24.2		40.3	—	17.0
Ecuador		130.6	26.4	—	7.7		20.3	—	5.2
Malaysia		935.8	54.0	—	(16.9	)	62.1	—	9.7
Other		98.3	1.2	—	(7.8	)	.9	—	(24.3	)

Total		3,876.8	510.1	15.1	161.6		450.9	11.0	124.9

Refining and marketing
North America		1,721.3	2,261.7	—	(37.1	)	1,758.4	—	(8.3	)
United Kingdom		349.9	215.3	—	(.2	)	195.0	—	2.8

Total		2,071.2	2,477.0	—	(37.3	)	1,953.4	—	(5.5	)

Total operating segments		5,948.0	2,987.1	15.1	124.3		2,404.3	11.0	119.4
Corporate and other		559.4	4.2	—	(10.4	)	10.6	—	(6.2	)

Total	$	6,507.4	2,991.3	15.1	113.9		2,414.9	11.0	113.2

*	Additional details about results of oil and gas operations are presented in the tables on page 20.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – Accounting Matters

In October 2004, the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (the “Act”) became law. The FASB issued FSP 109-1 in December 2004 to provide guidance on the application of SFAS No. 109, Accounting for Income Taxes, to the provision within the Act that provides, beginning in 2005, a tax deduction on qualified production activities. The tax deduction phases in at 3% beginning in 2005 and reaches 9% in 2010. FSP 109-1 concluded that the tax benefits for the deduction should be recognized as realized. This FSP was effective upon issuance and the Company applied it in computing U.S. income tax beginning in 2005. The Company recorded tax benefits of approximately $0.3 million and $0.6 million in the three-month periods ended March 31, 2006 and 2005, respectively, related to the Act.

In March 2005, the Emerging Issues Task Force decided in Issue 04-6 that mining operations should account for post-production stripping costs as a variable production cost that should be considered a component of mineral inventory costs. The Company’s synthetic oil operation at Syncrude is affected by this ruling, which is effective as of January 1, 2006 for the Company. The Company has determined that the level of bitumen inventory at Syncrude affected by this EITF consensus is immaterial and it has continued to expense post-production stripping costs as incurred.

SFAS No. 151, Inventory Costs, was issued by the FASB in November 2004. This statement amends Accounting Research Bulletin No. 43, to clarify that abnormal amounts of idle facility expense, freight, handling costs and wasted materials should be recognized as current-period charges, and it also requires that allocation of fixed production overheads be based on the normal capacity of the related production facilities. The Company adopted the provisions of this statement beginning January 1, 2006, and it had no impact on its results of operations.

In September 2005, the EITF decided in Issue 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, that two or more exchange transactions involving inventory with the same counterparty that are entered into in contemplation of one another should be combined for purposes of evaluating the effect of APB Opinion 29, Accounting for Nonmonetary Transactions. Additionally, the EITF decided that a nonmonetary exchange where an entity transfers finished goods inventory in exchange for the receipt of raw materials or work-in-progress inventory within the same line of business should generally be recognized by the entity at fair value. This consensus will be applied to new arrangements entered into beginning April 1, 2006, and to all inventory transactions that are completed after December 15, 2006 for arrangements entered into prior to March 15, 2006. The Company does not expect the adoption of this consensus to have a significant impact on its financial statements.

Note L – Commitments

The Company has entered into contracts to hire various drilling rigs and associated equipment for periods beyond March 31, 2006. These rigs are primarily utilized for deepwater drilling operations in the Gulf of Mexico and Malaysia. These commitments, all of which expire by 2008, total $423 million. A portion of these costs will be borne by other working interest owners when the wells are drilled. These drilling costs are expected to be accounted for as capital expenditures as incurred during the contract periods.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION

Results of Operations

Murphy’s net income in the first quarter of 2006 was $113.9 million, $.60 per diluted share, essentially level with net income of $113.2 million, $.60 per diluted share, in the same quarter a year ago. In 2006, substantially higher income for the Company’s exploration and production operations was mostly offset by losses in the refining and marketing business caused by downtime and unrecoverable repair costs at the Meraux, Louisiana refinery following Hurricane Katrina. Murphy’s net income by operating segment is presented below.


	Income (Loss)
	Three Months Ended March 31,
(Millions of dollars)	2006			2005
Exploration and production	$	161.6		124.9
Refining and marketing		(37.3	)	(5.5	)
Corporate		(10.4	)	(6.2	)

Net income	$	113.9		113.2

Murphy’s income from exploration and production operations was $161.6 million in the first quarter of 2006 compared to $124.9 million in the first quarter of 2005. Higher realized sales prices for crude oil and natural gas were the primary reasons for improved earnings. In addition, the 2006 period included lower exploration expenses and $15.7 million of insurance proceeds related to Gulf of Mexico production lost in the fourth quarter 2005 following Hurricane Katrina. Partially offsetting these improvements were lower oil and natural gas sales volumes and higher production expenses. Exploration expense in the 2006 period was $63.2 million, down from $70.3 million in 2005. Dry hole expense was lower by $14.2 million in the 2006 period mostly due to less unsuccessful exploration drilling costs in the Republic of Congo and the United States that were partially offset by higher costs in Malaysia. Geological and geophysical costs increased $8.7 million in 2006 compared to 2005 with higher costs in the United States and Malaysia due to seismic and other studies. The Company’s refining and marketing operations incurred a loss of $37.3 million in the 2006 quarter compared to a loss of $5.5 million in the 2005 quarter. The larger loss in 2006 was mostly caused by foregone refining margins, coupled with expenses for ongoing costs and $13 million of unrecoverable Hurricane Katrina-related repairs at the Meraux, Louisiana refinery, which was shut down for the entire first quarter. Corporate functions reflected a loss of $10.4 million in the 2006 quarter compared to a loss of $6.2 million in the same period in 2005. The 2006 period included lower interest income, unfavorable foreign exchange effects and higher equity compensation expense compared to 2005, but these were partially offset by lower net interest expense.

Exploration and Production

Results of exploration and production operations are presented by geographic segment below.


	Income (Loss)
	Three Months Ended March 31,
(Millions of dollars)	2006			2005
Exploration and production
United States	$	86.4		61.9
Canada		68.0		55.4
United Kingdom		24.2		17.0
Ecuador		7.7		5.2
Malaysia		(16.9	)	9.7
Other International		(7.8	)	(24.3	)

Total	$	161.6		124.9

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

Exploration and production operations in the United States reported quarterly earnings of $86.4 million in the first quarter of 2006 compared to $61.9 million in the 2005 quarter. This increase was primarily due to higher oil and natural gas sales prices and insurance proceeds of $15.7 million related to Gulf of Mexico production lost in the fourth quarter 2005 following Hurricane Katrina. These variances were partially offset by lower oil and natural gas production volumes. First quarter 2005 production included approximately 4,600 barrels of oil equivalent per day from properties on the continental shelf of the Gulf of Mexico that were sold during the second quarter of 2005. In addition, production was lower at the Medusa and Habanero fields in the deepwater Gulf of Mexico. The Seventeen Hands field in the deepwater Gulf of Mexico commenced production on March 1 and averaged 12 million cubic feet per day net to the Company during the start-up period in March. Production and depreciation expenses decreased in association with lower crude oil and natural gas sales volumes. Exploration expense decreased $11.3 million versus the prior period primarily due to lower dry hole costs in the deepwater Gulf of Mexico partially offset by higher geological and geophysical costs in the 2006 period.

Earnings from operations in Canada were $68 million in the 2006 quarter versus $55.4 million in the 2005 quarter. Canadian operations realized higher crude oil and natural gas sales prices in the current period, but these were partially offset by decreased offshore oil sales volumes. Heavy oil production volumes were higher in 2006, but heavy oil differentials widened significantly in the 2006 quarter, limiting the income impact from increased heavy oil sales. Production expense increased in the most recent period due to higher heavy oil sales volume, higher purchased energy costs and more maintenance costs at Syncrude and a higher Canadian exchange rate. Terra Nova production costs were up due to higher maintenance costs.

U.K. operations earned $24.2 million in the 2006 period versus $17 million in the same quarter a year ago as higher realized oil and natural gas prices during the period more than offset slightly lower sales volumes for crude oil.

Operations in Ecuador earned $7.7 million in 2006 compared to $5.2 million a year ago. The improved results were primarily due to higher oil sales prices partially offset by lower sales volumes and higher production expense in the current period.

Malaysia reported a loss of $16.9 million in the first quarter of 2006 compared to earnings of $9.7 million in the same period in 2005. The current period’s results were unfavorable to 2005 due to significantly higher exploration expenses, primarily higher dry hole and 3-D seismic costs, certain of which do not receive income tax benefit. Lower sales volumes and higher production expense also contributed to the lower income in the 2006 period.

Other international operations reported a loss of $7.8 million in the 2006 period versus a loss of $24.3 million in the same period a year ago. The lower loss was primarily due to less dry hole expense in the Republic of Congo during the 2006 period.

On a worldwide basis, the Company’s crude oil and condensate sales price averaged $49.11 per barrel for the 2006 first quarter compared to $39.90 per barrel in the first quarter of 2005. Average crude oil and liquids production was 98,074 barrels per day, down 10,664 barrels per day or 10% versus the 2005 period. Average oil sales volumes decreased 7% to 100,809 barrels per day. The decrease in crude oil production volumes was mostly attributable to lower production at Terra Nova, offshore eastern Canada, caused by operational problems with production equipment, lower entitlement due to higher oil prices at West Patricia, offshore Sarawak, Malaysia, and lower production from the Habanero and Medusa fields in the deepwater Gulf of Mexico. Heavy oil production in Canada in 2006 exceeded the prior year due to an ongoing development drilling program in the Seal area of northern Alberta. North American natural gas sales prices averaged $9.38 per thousand cubic feet (MCF) in the most recent quarter compared to $6.71 per MCF in the same quarter of 2005. Total natural gas sales volumes averaged 84 million cubic feet per day in 2006, down from 113 million cubic feet per day in the same period a year ago. The decrease was primarily attributable to the sale in mid-2005 of most properties located on the continental shelf of the Gulf of Mexico, for which sales volumes were 20 million cubic feet per day in the 2005 first quarter. The remaining reduction in natural gas sales volumes was mostly attributable to lower production at the Habanero field and onshore in Vermilion Parish, Louisiana. The Seventeen Hands field in the deepwater Gulf of Mexico commenced production on March 1, 2006 and averaged 12 million cubic feet per day net to the Company during the start-up period.

Additional details about results of oil and gas operations are presented in the tables on page 20.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

Selected operating statistics for the three-month periods ended March 31, 2006 and 2005 follow.


	Three Months Ended March 31,
	2006		2005
Net crude oil, condensate and gas liquids produced – barrels per day		98,074	108,738
United States		26,499	32,816
Canada – light		413	644
– heavy		15,181	10,953
– offshore		18,481	25,003
– synthetic		10,137	7,795
United Kingdom		8,098	8,702
Malaysia		10,942	15,181
Ecuador		8,323	7,644

Net crude oil, condensate and gas liquids sold – barrels per day		100,809	108,894
United States		26,499	32,816
Canada – light		413	644
– heavy		15,181	10,953
– offshore		19,566	24,145
– synthetic		10,137	7,795
United Kingdom		7,801	8,225
Malaysia		13,594	15,875
Ecuador		7,618	8,441

Net natural gas sold – thousands of cubic feet per day		83,590	112,502
United States		59,577	90,798
Canada		10,101	11,851
United Kingdom		13,912	9,853

Total net hydrocarbons produced – equivalent barrels per day (1)		112,006	127,488
Total net hydrocarbons sold – equivalent barrels per day (1)		114,741	127,644

Weighted average sales prices Crude oil and condensate – dollars per barrel (2)
United States	$	54.09	42.35
Canada (3) – light		55.72	46.92
– heavy (4)		17.67	14.68
– offshore		59.64	43.61
– synthetic		60.03	52.48
United Kingdom		60.86	47.72
Malaysia (5)		50.39	43.31
Ecuador		38.50	26.77
Natural gas – dollars per thousand cubic feet
United States (2)	$	9.53	6.79
Canada (3)		8.52	6.10
United Kingdom (3)		7.92	5.48

(1)	Natural gas converted on an energy equivalent basis of 6:1

(2)	Includes intracompany transfers at market prices.

(3)	U.S. dollar equivalent.

(4)	Includes the effects of the Company’s hedging program.

(5)	Price is net of a payment under the terms of the production sharing contract for Block SK 309.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

OIL AND GAS OPERATING RESULTS (unaudited)


(Millions of dollars)	United States		Canada	United Kingdom	Ecuador	Malaysia		Other		Synthetic Oil – Canada	Total
Three Months Ended March 31, 2006
Oil and gas sales and other operating revenues	$	197.9	138.1	52.8	26.4	54.0		1.2		54.8	525.2
Production expenses		15.6	19.8	4.5	6.6	8.3		–		30.7	85.5
Depreciation, depletion and amortization		23.4	29.4	6.7	5.5	12.7		.1		3.5	81.3
Accretion of asset retirement obligations		.7	1.0	.4	—	.1		.2		.1	2.5
Net costs associated with hurricanes		.5	—	—	—	—		—		—	.5
Exploration expenses
Dry holes		2.6	—	—	1.1	29.9		3.5		—	37.1
Geological and geophysical		11.7	.1	—	—	6.3		.6		—	18.7
Other		.5	.1	—	—	.2		1.2		—	2.0

		14.8	.2	—	1.1	36.4		5.3		—	57.8
Undeveloped lease amortization		4.1	.9	—	—	—		.4		—	5.4

Total exploration expenses		18.9	1.1	—	1.1	36.4		5.7		—	63.2

Selling and general expenses		5.5	2.5	.9	.2	2.6		2.8		.2	14.7
Income tax provisions		46.9	29.8	16.1	5.3	10.8		.2		6.8	115.9

Results of operations (excluding corporate overhead and interest)	$	86.4	54.5	24.2	7.7	(16.9	)	(7.8	)	13.5	161.6

Three Months Ended March 31, 2005
Oil and gas sales and other operating revenues	$	182.7	118.8	40.3	20.3	62.1		.9		36.8	461.9
Production expenses		24.0	13.9	3.7	5.7	6.8		—		20.6	74.7
Depreciation, depletion and amortization		26.3	31.8	5.9	4.5	12.3		—		2.9	83.7
Accretion of asset retirement obligations		1.1	.8	.4	—	.1		.1		.1	2.6
Exploration expenses
Dry holes		15.6	—	—	—	15.0		20.7		—	51.3
Geological and geophysical		8.1	.3	—	—	1.6		—		—	10.0
Other		.7	.1	.1	—	—		1.1		—	2.0

		24.4	.4	.1	—	16.6		21.8		—	63.3
Undeveloped lease amortization		5.8	.8	—	—	—		.4		—	7.0

Total exploration expenses		30.2	1.2	.1	—	16.6		22.2		—	70.3

Selling and general expenses		4.2	2.3	.9	.1	2.1		2.6		.2	12.4
Income tax provisions		35.0	22.2	12.3	4.8	14.5		.3		4.2	93.3

Results of operations (excluding corporate overhead and interest)	$	61.9	46.6	17.0	5.2	9.7		(24.3	)	8.8	124.9

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Refining and Marketing

Refining and marketing operations in North America reported a loss of $37.1 million during the first quarter of 2006 compared to a loss of $8.3 million in the same period a year ago. The larger loss was primarily caused by foregone refining margins, coupled with expenses for ongoing costs and $13.0 million of unrecoverable Hurricane Katrina-related repairs at the Meraux, Louisiana refinery, which was shut down for the entire first quarter. Although most repair costs are recoverable from insurance, damages caused by flooding have certain coverage limits. Additional pretax repair costs of approximately $37 million are expected to be expensed in the second quarter 2006. Commissioning and start up, which are anticipated to last several weeks at Meraux, began the first week of May. Similar to the 2005 first quarter, the 2006 quarter’s results for U.S. retail marketing operations were unfavorably affected by generally rising wholesale gasoline prices that squeezed margins. Refining and marketing operations in the U.K. lost $0.2 million in the 2006 period, down from a $2.8 million profit in the same quarter of 2005, with the weaker results based on operating margins that were hurt by higher crude prices during the 2006 period. Worldwide refinery inputs were 64,059 barrels per day in the first quarter of 2006 compared to 182,304 barrels per day in the 2005 quarter; refinery inputs were lower primarily due to the Company’s Meraux refinery being shut down for the entire 2006 quarter. Petroleum product sales were 336,378 barrels per day, down from 357,044 a year ago, also affected by Meraux downtime. The Company operated 120 more gasoline stations at Wal-Mart stores in the United States at March 31, 2006 compared to March 31, 2005.

Selected operating statistics for the three-month periods ended March 31, 2006 and 2005 follow.


	Three Months Ended March 31,
	2006	2005
Refinery inputs – barrels per day	64,059	182,304
North America	33,443	143,742
United Kingdom	30,616	38,562

Petroleum products sold – barrels per day	336,378	357,044
North America	304,389	318,410
Gasoline	246,794	210,838
Kerosine	4,243	10,874
Diesel and home heating oils	47,189	68,630
Residuals	2,691	23,194
Asphalt, LPG and other	3,472	4,874
United Kingdom	31,989	38,634
Gasoline	11,832	10,436
Kerosine	3,301	2,833
Diesel and home heating oils	9,557	17,509
Residuals	3,135	4,332
LPG and other	4,164	3,524

Corporate and other

Corporate activities, which include interest income and expense, foreign exchange effects, and corporate overhead not allocated to operating functions, reported a loss of $10.4 million in the 2006 quarter compared to a loss of $6.2 million in the first quarter of 2005. The 2006 period included lower interest income, unfavorable foreign exchange effects and higher equity compensation expense compared to 2005, but these were partially offset by lower net interest expense. The 2005 period included interest income on a U.S. tax settlement. Lower net interest expense in 2006 was mostly due to more interest being capitalized on oil development projects.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Financial Condition

Net cash provided by operating activities was $183.8 million for the first three months of 2006 compared to $206.6 million during the same period in 2005. Changes in operating working capital other than cash and cash equivalents used cash of $79.9 million in the first quarter of 2006 and $57.3 million in the 2005 period. The use of cash in the 2006 period was mostly attributable to higher accounts receivable from insurance companies related to hurricane-related repairs and clean up at the Meraux refinery.

Other predominant uses of cash in both years were for dividends, which totaled $21.0 million in 2006 and $20.7 million in 2005, and for capital expenditures, which, including amounts expensed, are summarized in the following table.


	Three Months Ended March 31,
(Millions of dollars)	2006			2005
Capital expenditures
Exploration and production	$	267.8		236.0
Refining and marketing		30.6		34.0
Corporate and other		1.8		1.3

Total capital expenditures		300.2		271.3
Geological, geophysical and other exploration expenses charged to income		(20.7	)	(12.0	)

Total property additions and dry holes	$	279.5		259.3

Working capital (total current assets less total current liabilities) at March 31, 2006 was $527.4 million, down $24.5 million from December 31, 2005. This level of working capital does not fully reflect the Company’s liquidity position, because the lower historical costs assigned to inventories under last-in first-out accounting were $424.6 million below fair value at March 31, 2006.

At March 31, 2006, long-term notes payable of $598 million and long-term nonrecourse debt of a subsidiary of $11.6 million were virtually unchanged from December 31, 2005. A summary of capital employed at March 31, 2006 and December 31, 2005 follows.


	March 31, 2006			Dec. 31, 2005
(Millions of dollars)	Amount		%	Amount		%
Capital employed
Notes payable	$	598.0	14.3	$	597.9	14.7
Nonrecourse debt of a subsidiary		11.6	.3		11.6	.3
Stockholders’ equity		3,566.0	85.4		3,461.0	85.0

Total capital employed	$	4,175.6	100.0	$	4,070.5	100.0

On April 25, 2006, Moody’s Investors Service lowered the Company’s long-term debt rating from “Baa1” to “Baa2”. On May 3, 2006, Standard & Poor’s lowered the Company’s rating from “A-” to “BBB”. The Company’s ratio of earnings to fixed charges was 16.6 to 1 for the first quarter of 2006.

Accounting and Other Matters

In October 2004, the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (the “Act”) became law. The FASB issued FSP 109-1 in December 2004 to provide guidance on the application of SFAS No. 109, Accounting for Income Taxes, to the provision within the Act that provides a tax deduction on qualified production activities. The tax deduction phases in at 3% beginning in 2005 and reaches 9% in 2010. FSP 109-1 concluded that the tax benefit for the deduction should be recognized as realized. This FSP was effective upon issuance and the Company applied it in computing U.S. income tax expense beginning in 2005. The Company recorded tax benefits of approximately $0.3 million and $0.6 million in the three-month periods ended March 31, 2006 and 2005, respectively, related to the Act.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Accounting and Other Matters (Contd.)

Murphy holds a 20% interest in Block 16 Ecuador, where the Company and its partners produce oil for export. In 2001, the local tax authorities announced that Value Added Taxes (VAT) paid on goods and services related to Block 16 and many oil fields held by other companies will no longer be reimbursed. In response to this announcement, the operator of Block 16 filed numerous actions in the Ecuador Tax Court seeking determination that the VAT in question is reimbursable. In July 2004, international arbitrators ruled that VAT was recoverable by another oil company, but the State of Ecuador responded that it was not bound by this arbitral decision. As of March 31, 2006, the Company has a receivable of approximately $16.8 million related to VAT. Murphy believes that its claim for reimbursement of VAT under applicable Ecuador tax law is valid, and it does not expect that the resolution of this matter will have a material adverse affect on the Company’s net income, financial condition or liquidity in future periods.

Outlook

Crude oil prices were at record levels in April 2006, but these prices have been quite volatile and have retreated slightly from these highs. The Company expects its oil and natural gas production in the second quarter of 2006 to average 113,000 barrels of oil equivalent per day compared to about 112,000 barrels of oil equivalent per day in the first quarter of 2006. Sales volumes in the second quarter of 2006 should exceed production by about 8,000 barrels per day, mostly due to settlement of a portion of the crude oil owed to the Company by partners in Block 16 Ecuador since 2004. Total Company production for the full year of 2006 is anticipated to average 110,000 barrels of oil equivalent per day. The Company’s Terra Nova field is scheduled to be shut down for major maintenance for virtually the entire third quarter of 2006. The Company’s share of maintenance expense for the Terra Nova project is anticipated to be about $14 million. On April 25, 2006, Ecuador changed its hydrocarbon law whereby the state would receive at least 50% of realized oil prices that exceed the base price in effect at the start of the contract as adjusted for inflation. Commissioning and start up of the Company’s Meraux, Louisiana refinery is currently underway. Further expense of about $37 million is projected for the second quarter 2006 associated with repair costs at Meraux that are not anticipated to be recoverable from insurance policies. In 2005, the U.K. government announced that the effective income tax rate for E&P companies will increase from 40% to 50% beginning in 2006. As of March 31, 2006, the Company has not recognized the estimated charge of approximately $15 million to increase the deferred and current income tax liabilities because the 10% rate increase has not been confirmed by the U.K. Parliament. This tax increase is expected to be approved by Parliament in the third quarter 2006. The Company currently anticipates total capital expenditures in 2006 of approximately $1.6 billion.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Forward-Looking Statements

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note F to this Form 10-Q report, Murphy makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.

Murphy was a party to natural gas price swap agreements at March 31, 2006 for a remaining notional volume of 0.5 million MMBTU that are intended to hedge the financial exposure of its Meraux, Louisiana refinery to fluctuations in the future price of a portion of natural gas to be purchased for fuel in 2006. In each month of settlement, the swaps require Murphy to pay an average natural gas price of $3.35 per MMBTU and to receive the average NYMEX price for the final three trading days of the month. At March 31, 2006, the estimated fair value of these agreements was recorded as an asset of $2.5 million. A 10% increase in the average NYMEX price of natural gas would have increased this asset by $.4 million, while a 10% decrease would have reduced the asset by a similar amount.

At March 31, 2006, the Company was a party to forward sale contracts covering 4,000 barrels per day in blended heavy oil sales during 2006. The contracts are intended to hedge the financial exposure of the Company’s blended heavy oil sales in Canada during the respective contract period and are priced at $25.23 per barrel. At March 31, 2006, the estimated fair value of these agreements was recorded as a $26.9 million liability. A 10% increase in the price of Canadian heavy oil at the Hardisty terminal in Canada would have increased this liability by $2.7 million, while a 10% decrease would have decreased this liability by a similar amount.

ITEM 4. CONTROLS AND PROCEDURES

Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

There were no significant changes in the Company’s internal controls over financial reporting that occurred during the first quarter of 2006 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

In December 2000, two of the Company’s Canadian subsidiaries, Murphy Oil Company Ltd. (MOCL) and Murphy Canada Exploration Company (MCEC) as plaintiffs filed an action in the Court of Queen’s Bench of Alberta seeking a constructive trust over oil and gas leasehold rights to Crown lands in British Columbia. The suit alleges that the defendants, The Predator Corporation Ltd. and Predator Energies Partnership (collectively Predator) and Ricks Nova Scotia Co. (Ricks), acquired the lands after first inappropriately obtaining confidential and proprietary data belonging to the Company and its partner. In January 2001, Ricks, representing an undivided 75% interest in the lands in question, settled its portion of the litigation by conveying its interest to the Company and its partner at cost. In 2001, Predator, representing the remaining undivided 25% of the lands in question, filed a counterclaim against MOCL and MCEC and MOCL’s President individually seeking compensatory damages of C$3.61 billion. In September 2004 the court summarily dismissed all claims against MOCL’s president and all but C$356 million of the counterclaim against the Company. On February 28, 2006, the Court of Appeals ruled in favor of the Company and affirmed the dismissal order. The Company believes that the counterclaim is without merit, that the amount of damages sought is frivolous and the likelihood of a material loss to the Company is remote. A trial concerning the 25% disputed interest and any remaining issues began on April 24, 2006. While no assurance can be given about the outcome, the Company does not believe that the ultimate resolution of this suit will have a material adverse effect on its net income, financial condition or liquidity in a future period. In the unlikely event that Predator were to prevail in its counterclaim for an amount approximating the damages sought, the result would have a material adverse effect on the Company’s net income, financial condition and liquidity.

Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of matters referred to in this item is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

ITEM 1A. RISK FACTORS

The Company has not identified any additional risk factors not previously disclosed in its Form 10-K/A filed on March 16, 2006.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)	The Exhibit Index on page 28 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 January 12, 2006 that included a News Release regarding the Company’s expected results of operations for the quarter ended December 31, 2005.

(c)	A report on Form 8-K was filed on February 2, 2006 that included a News Release announcing the Company’s earnings and certain other financial information for the three-month and twelve-month periods ended December 31, 2005.

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)
May 5, 2006
(Date)

EXHIBIT INDEX


Exhibit No.
12.1*		Computation of Ratio of Earnings to Fixed Charges

31.1*		Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2*		Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32		Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

*	This exhibit is incorporated by reference within this Form 10-Q.

Exhibits other than those listed above have been omitted since they are either not required or not applicable.

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