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 June 30, 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 June 30, 2006 was 186,840,652.

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		18

Item 3. Quantitative and Qualitative Disclosures About Market Risk		26

Item 4. Controls and Procedures		27

Part II – Other Information

Item 1. Legal Proceedings		27

Item 1A. Risk Factors		28

Item 4. Submission of Matters To A Vote of Security Holders		28

Item 6. Exhibits and Reports on Form 8-K		28

Signature		29

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)


	(Unaudited)
	June 30, 2006			December 31, 2005
ASSETS
Current assets
Cash and cash equivalents	$	414,712		585,333
Accounts receivable, less allowance for doubtful accounts of $14,970 in 2006 and $14,508 in 2005		1,047,420		865,155
Inventories, at lower of cost or market
Crude oil and blend stocks		113,238		83,265
Finished products		271,624		146,753
Materials and supplies		108,784		84,937
Prepaid expenses		149,941		33,239
Deferred income taxes		41,961		40,264

Total current assets		2,147,680		1,838,946

Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $2,703,483 in 2006 and $2,459,022 in 2005		4,784,782		4,374,229
Goodwill, net		46,025		44,206
Deferred charges and other assets		123,112		111,130

Total assets	$	7,101,599		6,368,511

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	4,665		4,490
Accounts payable and accrued liabilities		1,274,876		1,176,634
Income taxes payable		93,328		105,884

Total current liabilities		1,372,869		1,287,008

Notes payable		868,025		597,926
Nonrecourse debt of a subsidiary		7,468		11,648
Deferred income taxes		587,688		614,091
Asset retirement obligations		185,012		176,823
Accrued major repair costs		62,997		55,350
Deferred credits and other liabilities		171,335		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 186,926,283 shares in 2006 and 186,828,618 shares in 2005		186,926		186,829
Capital in excess of par value		429,329		437,963
Retained earnings		3,030,225		2,744,274
Accumulated other comprehensive income		201,957		131,324
Unamortized restricted stock awards		–		(16,410	)
Treasury stock, 85,631 shares of Common Stock in 2006 and 881,940 shares in 2005, at cost		(2,232	)	(22,990	)

Total stockholders’ equity		3,846,205		3,460,990

Total liabilities and stockholders’ equity	$	7,101,599		6,368,511

See Notes to Consolidated Financial Statements, page 7.

The Exhibit Index is on page 30.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

(Thousands of dollars except per share amounts)


	Three Months Ended June 30,					Six Months Ended June 30,
	2006			2005		2006		2005
REVENUES
Sales and other operating revenues	$	3,798,032		2,771,712		6,785,151		5,175,713
Gain (loss) on sale of assets		(109	)	171,613		(1,373	)	171,924
Interest and other income		995		6,617		6,403		17,177

Total revenues		3,798,918		2,949,942		6,790,181		5,364,814

COSTS AND EXPENSES
Crude oil and product purchases		2,996,955		1,966,451		5,304,451		3,755,995
Operating expenses		282,830		226,787		514,994		430,430
Exploration expenses, including undeveloped lease amortization		30,273		40,010		93,436		110,305
Selling and general expenses		46,559		40,459		87,031		76,764
Depreciation, depletion and amortization		102,206		109,039		199,564		213,793
Net costs associated with hurricanes		43,051		—		78,773		—
Accretion of asset retirement obligations		2,576		2,493		5,076		5,132
Interest expense		11,678		11,501		22,241		23,537
Interest capitalized		(9,039	)	(8,755	)	(18,628	)	(16,322	)

Total costs and expenses		3,507,089		2,387,985		6,286,938		4,599,634

Income before income taxes		291,829		561,957		503,243		765,180
Income tax expense		77,754		214,164		175,296		304,234

NET INCOME	$	214,075		347,793		327,947		460,946

INCOME PER COMMON SHARE
NET INCOME – BASIC	$	1.15		1.89		1.76		2.51
NET INCOME – DILUTED	$	1.13		1.85		1.73		2.46

Average common shares outstanding – basic		185,919,897		183,903,885		185,813,948		183,902,337
Average common shares outstanding – diluted		189,101,235		187,682,605		189,047,627		187,586,344

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 June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
Net income	$	214,075	347,793		327,947		460,946

Other comprehensive income (loss), net of tax
Cash flow hedges
Net derivative gains (losses)		2,941	(5,334	)	(8,837	)	(19,301	)
Reclassification to income		405	(415	)	8,952		(704	)

Total cash flow hedges		3,346	(5,749	)	115		(20,005	)
Minimum pension liability adjustment		—	—		13		—
Net gain (loss) from foreign currency translation		71,865	(13,653	)	70,505		(14,504	)

COMPREHENSIVE INCOME	$	289,286	328,391		398,580		426,437

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)


	Six Months Ended June 30,
	2006			2005
OPERATING ACTIVITIES
Net income	$	327,947		460,946
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		199,564		213,793
Provisions for major repairs		15,325		19,639
Expenditures for major repairs and asset retirements		(10,624	)	(27,798	)
Dry hole costs		41,200		60,071
Amortization of undeveloped leases		11,030		12,107
Accretion of asset retirement obligations		5,076		5,132
Deferred and noncurrent income tax charge (benefit)		(22,104	)	3,774
Pretax (gain) loss from disposition of assets		1,373		(171,924	)
Net increase in noncash operating working capital		(393,669	)	(102,494	)
Other operating activities, net		8,932		(20,879	)

Net cash provided by operating activities		184,050		452,367

INVESTING ACTIVITIES
Property additions and dry hole costs		(610,479	)	(576,402	)
Proceeds from sales of assets		12,195		160,421
Proceeds from maturities of marketable securities		—		17,892
Other – net		(6,137	)	(6,259	)

Net cash required by investing activities		(604,421	)	(404,348	)

FINANCING ACTIVITIES
Increase (decrease) in notes payable		269,989		(19,233	)
Decrease in nonrecourse debt of a subsidiary		(4,667	)	(4,193	)
Proceeds from exercise of stock options and employee stock purchase plans		11,109		337
Excess tax benefits related to exercise of stock options		5,217		—
Cash dividends paid		(41,996	)	(41,497	)
Other		—		(1,052	)

Net cash provided by (used in) financing activities		239,652		(65,638	)

Effect of exchange rate changes on cash and cash equivalents		10,098		(10,173	)

Net decrease in cash and cash equivalents		(170,621	)	(27,792	)
Cash and cash equivalents at January 1		585,333		535,525

Cash and cash equivalents at June 30	$	414,712		507,733

SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid, net of refunds	$	263,550		305,293

Interest paid, net of amounts capitalized		2,615		6,456

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

(Thousands of dollars)


	Six Months Ended June 30,
	2006			2005
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued		—		—

Common Stock – par $1.00, authorized 450,000,000 shares; issued 186,926,283 shares in 2006 and 186,828,618 shares in 2005
Balance at beginning of period	$	186,829		94,613
Exercise of stock options		97		—
Two-for-one stock split effective June 3, 2005		—		92,216

Balance at end of period		186,926		186,829

Capital in Excess of Par Value
Balance at beginning of period		437,963		511,045
Exercise of stock options, including income tax benefits		3,717		—
Restricted stock transactions and other		(7,433	)	15,909
Amortization, forfeitures and other		11,186		—
Sale of stock under employee stock purchase plans		306		216
Two-for-one stock split effective June 3, 2005		—		(92,216	)
Reclassification from Unamortized Restricted Stock Awards upon adoption of SFAS No. 123 R		(16,410	)	—

Balance at end period		429,329		434,954

Retained Earnings
Balance at beginning of period		2,744,274		1,981,020
Net income for the period		327,947		460,946
Cash dividends		(41,996	)	(41,497	)

Balance at end of period		3,030,225		2,400,469

Accumulated Other Comprehensive Income
Balance at beginning of period		131,324		134,509
Foreign currency translation gains (losses), net of taxes		70,505		(14,504	)
Cash flow hedging gains (losses), net of taxes		115		(20,005	)
Minimum pension liability adjustment, net of taxes		13		—

Balance at end of period		201,957		100,000

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		—		(266	)

Balance at end of period		—		(21,348	)

Treasury Stock
Balance at beginning of period		(22,990	)	(67,293	)
Exercise of stock options		13,345		—
Sale of stock under employee stock purchase plans		390		121
Awarded restricted stock, net of forfeitures		7,023		4,659

Balance at end of period		(2,232	)	(62,513	)

Total Stockholders’ Equity	$	3,846,205		3,038,391

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 June 30, 2006, and the results of operations, cash flows and changes in stockholders’ equity for the three-month and six-month periods ended June 30, 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 of America, management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.

Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2005 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, 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 June 30, 2006, the Company had total capitalized drilling costs pending the determination of proved reserves of $390.7 million. The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30, 2006 and 2005.


(Thousands of dollars)	2006		2005
Beginning balance at January 1	$	275,256	106,105
Additions pending the determination of proved reserves		115,417	120,198

Balance at June 30	$	390,673	226,303

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
Capitalized exploratory well costs capitalized for one year or less	$	139,063	158,745
Capitalized exploratory well costs capitalized for more than one year		251,610	67,558

Balance at June 30	$	390,673	226,303

Number of projects that have exploratory well costs that have been capitalized for more than one year		12	5

Of the $251.6 million of exploratory well costs capitalized for more than one year, $67.9 million is in the U.S., $151.1 million is in Malaysia, $16.5 million is in Canada and $16.1 million is in the Republic of Congo. Of the U.S. amount, $61 million relates to a deepwater Gulf of Mexico field that is expected to be sanctioned for development in the second half of 2006. In Malaysia and the Republic of Congo, development plans are in various stages of completion or additional drilling is planned. In Canada, these costs are for stratigraphic wells that will be used for locating near-term horizontal heavy oil wells.

In June 2005, the Company completed the sale of mature oil and natural gas properties on the continental shelf of the Gulf of Mexico for a sale price of approximately $156.3 million after operating adjustments. Total net production from the properties sold amounted to approximately 4,000 barrels of oil equivalent per day during the six-month period ended June 30, 2005. The assets sold had a net book value of $33.5 million and an associated asset retirement obligation liability of $44.8 million. The Company recorded a gain before income taxes of approximately $168.9 million (after-tax gain $106.8 million) on this transaction, which is included in Gain on Sale of Assets on the Consolidated Statements of Income in 2005.

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 and six-month periods ended June 30, 2006 and 2005.


	Three Months Ended June 30,
	2006			2005		2006		2005
(Thousands of dollars)	Pension Benefits					Postretirement Benefits
Service cost	$	2,813		2,471		566		494
Interest cost		5,690		5,274		1,006		933
Expected return on plan assets		(5,421	)	(5,006	)	—		—
Amortization of prior service cost		395		67		(69	)	(71	)
Amortization of transitional asset		(162	)	(1	)	—		—
Recognized actuarial loss		1,639		1,406		446		360

Net periodic benefit expense	$	4,954		4,211		1,949		1,716


	Six Months Ended June 30,
	2006			2005		2006		2005
(Thousands of dollars)	Pension Benefits					Postretirement Benefits
Service cost	$	5,472		4,579		1,132		940
Interest cost		11,018		9,629		2,012		1,774
Expected return on plan assets		(10,452	)	(9,147	)	—		—
Amortization of prior service cost		762		118		(138	)	(135	)
Amortization of transitional asset		(318	)	(32	)	—		—
Recognized actuarial loss		3,166		2,519		892		684

Net periodic benefit expense	$	9,648		7,666		3,898		3,263

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 six-month period ended June 30, 2006, the Company made contributions of $4.5 million and remaining funding in 2006 for the Company’s domestic and foreign defined benefit pension and postretirement plans is anticipated to be $6.6 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, which has been deemed comparable to medicare coverage, to qualifying retirees under its retiree medical plan. The Company recognized estimated benefits of $0.8 million and $0.7 million in estimated benefits related to the Act in the first half of 2006 and 2005, respectively.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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 share-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 share-based plans during the three-month periods ended June 30, 2006 and 2005 were $7.4 million and $3.3 million, respectively. Related income tax benefits recognized in the income statement for the three-month periods ended June 30, 2006 and 2005 were $2.5 million and $1.2 million, respectively. Compensation costs charged against income for share-based plans during the six-month periods ended June 30, 2006 and 2005 were $13.9 million and $6.2 million, respectively. The related income tax benefits recognized in the income statement in these six-month periods of 2006 and 2005 were $4.8 million and $2.2 million, respectively.

As of June 30, 2006, there was $29.8 million in compensation costs to be expensed over approximately the next three years related to unvested share-based compensation arrangements granted by the Company. Cash received from options exercised under all share-based payment arrangements for the six-month periods ended June 30, 2006 and 2005 was $11.1 million and $0.3 million, respectively. The actual income tax benefits realized for the tax deductions from option exercises of the share-based payment arrangements totaled $6.1 million and less than $0.1 million for the six-month periods ended June 30, 2006 and 2005, respectively.

The Company has a history of issuing Treasury shares to satisfy share option exercises; however due to the limited number of remaining shares held in the Treasury, shares are now being issued 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 and six-month periods ended June 30, 2005, would have been the pro forma amounts shown in the following table.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – Incentive Plans (Contd.)


(Thousands of dollars except per share data)	Three-Months Ended June 30, 2005			Six-Months Ended June 30, 2005
Net income – As reported	$	347,793		460,946
Restricted stock compensation expense included in income, net of tax		1,412		2,573
Total stock-based compensation expense using fair value method for all awards, net of tax		(2,982	)	(5,583	)

Net income – Pro forma	$	346,223		457,936

Net income per share – As reported, basic	$	1.89		2.51
Pro forma, basic		1.88		2.49
As reported, diluted		1.85		2.46
Pro forma, diluted		1.84		2.44

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		0.90	%		1.25	%
Expected volatility		30.00	%		26.00	%
Risk-free interest rate		4.42	%		3.74	%
Expected life		4.75	yrs.		5.00	yrs.

Changes in stock options outstanding during the six-month periods ended June 30, 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	(609,602	)		17.17	—			—
Forfeitures and other	—			—	(69,880	)		14.04

Outstanding at June 30	8,592,535		$	25.50	9,902,700		$	21.02

Exercisable at June 30	6,332,381		$	18.22	7,051,740		$	16.35

The total intrinsic value of stock options exercised during the six-month period ended June 30, 2006 was $23.1 million. No stock options were exercised during the six-month period ended June 30, 2005.

Additional information about stock options outstanding at June 30, 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)
June 30, 2006	8,592,535	4.9	$	30.50	$	262,035	6,332,381	4.7	$	37.64	$	238,353
June 30, 2005	9,902,700	5.8		31.21		309,052	7,051,740	5.4		35.88		253,027

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – Incentive Plans (Contd.)

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 six-month periods ended June 30, 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	(15,722	)	(2,000	)

Balance at June 30	728,473		491,000

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.

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		0.955
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-LAPSE 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-lapse 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 June 30	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 the option 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 14,958 shares at an average price of $46.52 per

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – Incentive Plans (Contd.)

share in the six-month period ended June 30, 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 June 30, 2006, 134,527 shares remained available for sale under the ESPP. The fair value per share of the ESPP was approximately $7.61 for the six-month period ended June 30, 2006.

SAVINGS-RELATED SHARE OPTION PLAN (SOP) – 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 Company stock at a price equal to 90% of the fair value of the stock as of the date of grant. The SOP 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 SOP plan an employee receives interest on withholdings and has six months to decide whether to use all or part of the withholdings plus credited interest to purchase shares of Company stock or receive a repayment of withholdings plus credited interest. Compensation costs related to the SOP 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 SOP Plans with holding periods that end in May 2007 and December 2009 were determined to be $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-month and six-month periods ended June 30, 2006 and 2005. The following table reconciles the weighted-average shares outstanding used for these computations.


	Three Months Ended June 30,		Six Months Ended June 30,
(Weighted-average shares)	2006	2005	2006	2005
Basic method	185,919,897	183,903,885	185,813,948	183,902,337
Dilutive stock options	3,181,338	3,778,720	3,233,679	3,684,007

Diluted method	189,101,235	187,682,605	189,047,627	187,586,344

Options to purchase 787,500 shares of common stock at a weighted average share price of $57.32 were outstanding during the three-month and six-month periods ended June 30, 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 three-month and six-month periods ended June 30, 2005.

Note F – Financing Arrangements

In May 2006, Murphy extended its five year committed credit facility for one year. The Company and certain wholly-owned subsidiaries may continue to borrow up to $1 billion under this facility with a major banking consortium through June 2010. The extension now permits the same entities to borrow up to $942.5 million under this facility through June 2011.

Note G – 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 June 30, 2006 of 0.4 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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

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 Accumulated Other Comprehensive Income (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 six-month periods ended June 30, 2006 and 2005, the Company received approximately $1.6 million and $2.3 million, respectively, for maturing swap agreements. For the three-month and six-month periods ended June 30, 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 posted price for blended heavy oil at the Hardisty terminal in Canada each month and will receive at that location a fixed price of $25.23 per barrel. 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 and six-month periods ended June 30, 2006 and 2005, the income effect from cash flow hedging ineffectiveness was insignificant. During the six-month periods ended June 30, 2006 and 2005 the Company paid approximately $14.1 and $1.1 million 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.

During the next six months, the Company expects to reclassify approximately $13.3 million in net after-tax losses from AOCI into earnings as the forecasted transactions covered by hedging instruments actually occur. All forecasted transactions currently being hedged are expected to occur by December 2006.

Note H – Accumulated Other Comprehensive Income

The components of Accumulated Other Comprehensive Income on the Consolidated Balance Sheets at June 30, 2006 and December 31, 2005 are presented in the following table.


(Thousands of dollars)	June 30, 2006			December 31, 2005
Foreign currency translation gain, net of tax	$	256,227		185,722
Cash flow hedging, net of tax		(13,344	)	(13,459	)
Minimum pension liability, net of tax		(40,926	)	(40,939	)

Accumulated other comprehensive income	$	201,957		131,324

The effect of SFAS Nos. 133/138, Accounting for Derivative Investments and Hedging Activities, increased AOCI for the six months ended June 30, 2006 by $0.1 million, net of $0.5 million in income taxes, and hedging ineffectiveness was not significant. Derivative instruments decreased AOCI for the six months ended June 30, 2005 by $20.0 million, net of $8.6 million in income taxes, and hedging ineffectiveness was not significant. The AOCI decrease in the first half of 2005 was primarily related to the change in fair value of blended heavy oil forward sales contracts described in Note G.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – Hurricane and Insurance Related Matters

In 2006, the Company recorded pretax expenses, net of anticipated insurance recoveries, of $78.8 million associated with hurricanes that occurred in the United States in 2005, including $77.5 million at the Meraux refinery. The components of these refinery costs included $39.5 million for repair costs not expected to be recovered due to certain coverage limits for the Company’s insurance policies, $5.9 million for incremental insurance costs, $7.1 million for other uninsured incremental expenses incurred, and $25.0 million for depreciation and salaries while the refinery was temporarily idled prior to restarting in May. 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 $10.0 to $15.0 million related to Hurricane Katrina in the third quarter 2006. See Note J for additional information regarding environmental and other contingencies relating to Hurricane Katrina. Total accounts receivable from insurers for hurricane-related matters was $185.0 million at June 30, 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 Consolidated Statement of Income for the six months ended June 30, 2006.

Note J – 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, may be taken without full consideration of their consequences, and may be taken in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.

In 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 three 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 these 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 three sites or other Superfund sites. The Company believes that its share of the ultimate costs to clean-up the three 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Environmental and Other Contingencies (Contd.)

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. Additional class action lawsuits have been consolidated with the first suit into a single action in the U.S. District Court for the Eastern District of Louisiana. The Court certified the class on January 30, 2006 and a trial as to liability is scheduled to commence in October 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.

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 was held in the second quarter 2006, but no decision has been issued. 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Environmental and Other Contingencies (Contd.)

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

In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide financial guarantees or letters of credit that may be drawn upon if the Company fails to perform under those contracts. At June 30, 2006, the Company had contingent liabilities of $8.5 million under a financial guarantee and $126.0 million on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to the guarantee and letters of credit because it believes that the likelihood of having these drawn is remote.

Note K – New Accounting Principles and Recent Accounting Pronouncements

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 has been applied to new arrangements entered into beginning April 1, 2006, and will be applied to all inventory transactions that are completed after December 15, 2006 for arrangements entered into prior to March 15, 2006. The adoption of this consensus in the second quarter 2006 did not have a significant impact on the Company’s financial statements.

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes. This interpretation clarifies the criteria for recognizing income tax benefits under FASB Statement No. 109, Accounting for Income Taxes, and requires additional financial statement disclosures about uncertain tax positions. The interpretation is effective beginning January 1, 2007. The Company is in the early stages of evaluating this interpretation and at the current time is unable to determine the impact on its financial statements.

In March 2005, the Emerging Issues Task Force decided in Issue 04-6 that mining operations should account for post-production stripping costs as a variable production cost that should be considered a component of mineral inventory costs. The Company’s synthetic oil 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.

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 $0.7 million and $2.4 million in the six-month periods ended June 30, 2006 and 2005, respectively, related to the Act.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note L – Commitments for Drilling Rigs

The Company has entered into contracts to hire various drilling rigs and associated equipment for periods beyond June 30, 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 $396 million. A significant portion of these costs are expected to be borne by other working interest owners when the wells are drilled. These drilling costs are generally expected to be accounted for as capital expenditures as incurred during the contract periods.

Note M – Income Taxes

Income tax expense for the three-month and six-month periods in 2006 includes a tax benefit of $37.5 million related to Canadian Federal and provincial tax rate reductions enacted by these governments in the second quarter 2006.

Note N – Business Segments


			Three Months Ended June 30, 2006				Three Months Ended June 30, 2005
(Millions of dollars)	Total Assets at June 30, 2006		External Revenues	Inter- segment Revenues	Income (Loss)		External Revenues	Inter- segment Revenues	Income (Loss)
Exploration and production*
United States	$	927.7	177.4	—	67.8		366.8	—	187.9
Canada		1,705.9	179.7	32.2	114.2		179.0	14.7	78.6
United Kingdom		213.1	69.1	—	32.5		48.5	—	20.7
Ecuador		128.3	42.7	—	13.4		22.7	—	7.3
Malaysia		1,123.0	67.1	—	21.9		60.9	—	2.2
Other		99.6	.9	—	(4.8	)	.9	—	(6.8	)

Total		4,197.6	536.9	32.2	245.0		678.8	14.7	289.9

Refining and marketing
North America		2,008.5	2,972.6	—	(26.3	)	2,129.0	—	59.7
United Kingdom		358.6	287.5	—	13.1		135.5	—	7.7

Total		2,367.1	3,260.1	—	(13.2	)	2,264.5	—	67.4

Total operating segments		6,564.7	3,797.0	32.2	231.8		2,943.3	14.7	357.3
Corporate and other		536.9	1.9	—	(17.8	)	6.6	—	(9.6	)

Total	$	7,101.6	3,798.9	32.2	214.0		2,949.9	14.7	347.7


	Six Months Ended June 30, 2006					Six Months Ended June 30, 2005
(Millions of dollars)	External Revenues		Inter- segment Revenues	Income (Loss)		External Revenues	Inter- segment Revenues	Income (Loss)
Exploration and production*
United States	$	375.3	—	154.2		549.5	—	249.8
Canada		357.5	47.3	182.2		323.6	25.7	134.0
United Kingdom		121.9	—	56.7		88.8	—	37.7
Ecuador		69.1	—	21.1		43.0	—	12.5
Malaysia		121.1	—	5.0		123.0	—	11.9
Other		2.1	—	(12.6	)	1.8	—	(31.1	)

Total		1,047.0	47.3	406.6		1,129.7	25.7	414.8

Refining and marketing
North America		5,234.3	—	(63.4	)	3,887.4	—	51.4
United Kingdom		502.8	—	12.9		330.5	—	10.5

Total		5,737.1	—	(50.5	)	4,217.9	—	61.9

Total operating segments		6,784.1	47.3	356.1		5,347.6	25.7	476.7
Corporate and other		6.1	—	(28.2	)	17.2	—	(15.8	)

Total	$	6,790.2	47.3	327.9		5,364.8	25.7	460.9

*	Additional details about results of oil and gas operations are presented in the tables on page 22.

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

Results of Operations

Murphy’s net income in the second quarter of 2006 was $214.0 million, $1.13 per diluted share, compared to net income of $347.7 million, $1.85 per diluted share, in the second quarter of 2005. The income reduction in 2006 primarily related to a gain in the 2005 second quarter of $106.8 million on sale of mature oil and gas properties on the continental shelf of the Gulf of Mexico and losses in the refining and marketing business in 2006 caused by downtime and unrecoverable repair costs at the Meraux, Louisiana refinery following Hurricane Katrina. The 2006 period included non-cash income tax benefits of $37.5 million related to Canadian Federal and provincial tax rate reductions enacted by these governments in the second quarter 2006. For the first six months of 2006, net income totaled $327.9 million, $1.73 per diluted share, compared to net income of $460.9 million, $2.46 per diluted share, for the same period in 2005. The lower year-to-date 2006 income was essentially caused by variances similar to those for the second quarter 2006. Murphy’s net income by operating segment is presented below:


	Income (Loss)
	Three Months Ended June 30,					Six Months Ended June 30,
(Millions of dollars)	2006			2005		2006		2005
Exploration and production	$	245.0		289.9		406.6		414.8
Refining and marketing		(13.2	)	67.4		(50.5	)	61.9
Corporate		(17.8	)	(9.6	)	(28.2	)	(15.8	)

Net income	$	214.0		347.7		327.9		460.9

In the current quarter, the Company’s exploration and production operations earned $245.0 million, compared to $289.9 million in the 2005 quarter. Income in this segment included $37.5 million in Canadian income tax benefits in the 2006 quarter. The 2005 second quarter included income of $106.8 million from a gain on the sale of U.S. Gulf of Mexico properties. Excluding these items from the respective periods, this segment’s earnings in the 2006 quarter were higher than in the 2005 quarter based mostly on higher oil sales prices. The 2006 period also benefited from lower exploration expense. Income in the 2006 period was unfavorably affected by lower crude oil and natural gas sales volumes compared to 2005. The Company’s refining and marketing operations incurred a loss of $13.2 million in the second quarter of 2006 compared to a profit of $67.4 million for the three months ended June 30, 2005. The Meraux refinery was down for repairs following Hurricane Katrina for a portion of the 2006 quarter prior to restarting in May. The earnings decline in the 2006 quarter was mostly due to downtime at Meraux and $26.5 million in unrecoverable Hurricane Katrina-related repair costs at this refinery. Income in the 2005 quarter benefited from strong margins at the Meraux refinery. The after-tax costs of the corporate function were $17.8 million in the 2006 second quarter compared to $9.6 million in the 2005 period with the cost increase due to unfavorable foreign currency exchange effects and higher compensation costs in 2006.

Net income was $327.9 million in the first six months of 2006 compared to $460.9 million in the same 2005 period. The Company’s exploration and production operations earned $406.6 million in the first half of 2006 compared to $414.8 million in the same period of 2005. Earnings in 2006 benefited from higher oil prices, the $37.5 million Canadian income tax benefit and $15.7 million of pretax insurance proceeds related to Gulf of Mexico production lost in the fourth quarter of 2005 following Hurricane Katrina, but the current period had lower oil and natural gas sales volumes. The 2005 period included a $106.8 million after-tax gain on sale of mature oil and gas properties in the Gulf of Mexico. The Company’s refining and marketing operations incurred a loss of $50.5 million in the first six months of 2006, compared to a profit of $61.9 million in the 2005 period. The current year unfavorable result was mostly due to downtime and repair costs at the Meraux refinery following Hurricane Katrina. Meraux incurred $39.5 million of repair costs during the period which are not expected to be recoverable from insurance. Corporate after-tax costs were $28.2 million in the 2006 period compared to costs of $15.8 million in the 2005 period. Unfavorable foreign currency exchange results and higher share-based compensation expense accounted for most of the higher net costs in 2006.

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

Results of Operations (Contd.)

Exploration and Production

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


	Income (Loss)
	Three Months Ended June 30,					Six Months Ended June 30,
(Millions of dollars)	2006			2005		2006		2005
Exploration and production
United States	$	67.8		187.9		154.2		249.8
Canada		114.2		78.6		182.2		134.0
United Kingdom		32.5		20.7		56.7		37.7
Ecuador		13.4		7.3		21.1		12.5
Malaysia		21.9		2.2		5.0		11.9
Other International		(4.8	)	(6.8	)	(12.6	)	(31.1	)

Total	$	245.0		289.9		406.6		414.8

Exploration and production operations in the United States reported earnings of $67.8 million in the second quarter of 2006 compared to earnings of $187.9 million a year ago. The 2005 period included a $106.8 million after-tax gain on sale of mature oil and gas properties in the Gulf of Mexico. Higher crude oil sales prices in the current period were more than offset by production declines in the deepwater Gulf of Mexico. Production expense in the 2006 period was less than 2005 due to lower crude oil and natural gas sales volumes and lower workover and repair expenses, with these partially offset by higher property insurance costs. Depreciation expense was lower in 2006 than in 2005 due to lower barrel equivalents produced and sold in the current period. Exploration expenses in the 2006 period increased $8.3 million from the prior year primarily due to higher dry hole costs and geological and geophysical expenses.

Operations in Canada earned $114.2 million this quarter compared to $78.6 million a year ago. The current period includes $37.5 million in income tax benefits related to Federal and provincial tax rate reductions that were enacted in the 2006 quarter. Excluding these income tax benefits, Canadian earnings declined slightly versus the same period a year ago. Higher crude oil sales prices were more than offset by lower production volumes and increased production expenses. Terra Nova shut down in May 2006 following mechanical equipment failure, and the field is expected to restart in October. Production expenses increased due to a combination of more crude oil sales volumes for higher-cost heavy oil, repair costs incurred at Terra Nova, and higher natural gas and compensation costs for the Company’s synthetic oil operation.

U.K. operations earned $32.5 million in the current quarter, up from $20.7 million in the prior year. The improvement was primarily due to higher crude oil and natural gas sales prices in the 2006 period compared to the 2005 quarter.

Operations in Ecuador earned $13.4 million in the second quarter of 2006 compared to $7.3 million a year ago. The 2006 period results improved primarily due to higher oil sales prices. Production and depreciation expenses were higher due to the increased oil sales volumes. The settlement of crude oil production volumes owed to the Company by two of its partners since 2004 added sales volumes of 9,375 barrels per day in the second quarter 2006; settlement negotiations as to transportation and other remaining issues are ongoing. The income effect of this second quarter settlement was virtually offset by revenue sharing with the government that was effective in April 2006.

Operations in Malaysia reported earnings of $21.9 million in the 2006 period compared to income of $2.2 million during the same period in 2005. The improvement in Malaysia was primarily due to higher crude oil sales prices in the current period and lower exploration expenses, a significant portion of which have no recorded tax benefit. Production and depreciation expense declined due to lower sales volumes in the 2006 period.

Other international operations reported a loss of $4.8 million in the second quarter of 2006 compared to a loss of $6.8 million in the comparable period a year ago. Lower exploration expenses in the Republic of Congo were the primary cause of the variance in results.

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

On a worldwide basis, the Company’s crude oil and condensate prices averaged $54.10 per barrel in the second quarter 2006 compared to $43.10 in the 2005 period. Average crude oil and liquids production was 90,695 barrels per day in the second quarter of 2006 compared to 111,030 barrels per day in the second quarter of 2005, with the decrease primarily attributable to a combination of lower production at the Terra Nova field offshore Eastern Canada and in the deepwater Gulf of Mexico. Crude oil sales volumes averaged 103,360 barrels per day in the second quarter 2006 compared to 114,526 barrels per day in the 2005 period. The previously mentioned partial settlement in Ecuador added sales volume of 9,375 barrels per day in the 2006 quarter. North American natural gas sales prices averaged $7.10 per thousand cubic feet (MCF) in the most recent quarter compared to $7.25 per MCF in the same quarter of 2005. Natural gas sales volumes averaged 87 million cubic feet a day in the second quarter 2006, down 20 million cubic feet per day from the 2005 quarter, primarily due to fields in the Gulf of Mexico that were sold in June 2005.

Operations in the United States for the six months ended June 30, 2006 produced income of $154.2 million compared to income of $249.8 million in 2005. The 2005 period included a $106.8 million after-tax gain on sale of mature oil and gas properties in the Gulf of Mexico. The 2006 period benefited from higher crude oil and natural gas sales prices, lower depreciation expense due to lower crude oil and natural gas sales volumes, and lower production expense associated with lower sales volumes and lower workover and repair costs partially offset by higher property insurance costs. Additionally, in the 2006 period, the Company received $15.7 million of pretax insurance proceeds related to Gulf of Mexico production lost in the fourth quarter of 2005 following Hurricane Katrina. Exploration expenses in the 2006 period decreased $3.0 million from the prior year. Higher geological and geophysical expenses were more than offset by lower dry hole costs and undeveloped lease amortization in the 2006 period.

In the first half of 2006, Canadian operations earned $182.2 million compared to $134.0 million a year ago. The 2006 period includes $37.5 million in income tax benefits related to Federal and provincial tax rate reductions that were enacted in the 2006 second quarter. Higher sales prices for oil and natural gas were partially offset by lower oil and natural gas sales volumes. Production expenses increased due to more crude oil sales volumes for higher-cost heavy oil, repair costs incurred at Terra Nova, and higher natural gas and compensation costs for the Company’s synthetic oil operation.

Income in the U.K. for the six-month period ended June 30, 2006 was $56.7 million compared to $37.7 million a year ago primarily due to higher crude oil and natural gas sales prices received.

For the first six months of 2006, earnings in Ecuador were $21.1 million compared to $12.5 million for the 2005 period. The 2006 period improvement is due primarily to higher crude oil sales volumes, partially offset by the effects of revenue sharing with the local government.

Malaysia operations earned $5.0 million in the first half of 2006 compared to earnings of $11.9 million a year ago. The effects of lower sales volumes and increased exploration expenses in 2006 were only partially offset by higher crude oil sales prices in the current period.

Other international operations reported a loss of $12.6 million in the first six months of 2006 compared to a loss of $31.1 million in the 2005 period. The higher loss in the 2005 period was primarily due to higher dry hole costs in the Republic of Congo in the 2005 period.

For the first six months of 2006, the Company’s sales price for crude oil and condensate averaged $51.67 per barrel compared to $41.55 per barrel in 2005. Crude oil and condensate production in the first half of 2006 averaged 94,365 barrels per day compared to 109,892 barrels per day a year ago. The decrease was mostly attributable to lower production at Terra Nova due to equipment downtime and lower volumes produced in the deepwater Gulf of Mexico. The average sales price for North American natural gas in the first six months of 2006 was $8.17 per MCF, up from $6.98 per MCF in 2005. Natural gas sales volumes were down from 110 million cubic feet per day in 2005 to 86 million cubic feet per day in 2006, with the decline due mostly to lower sales volumes from Gulf of Mexico fields sold in June 2005.

Additional details about results of oil and gas operations are presented in the tables on page 22.

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

Selected operating statistics for the three-month and six-month periods ended June 30, 2006 and 2005 follow.


	Three Months Ended June 30,			Six Months Ended June 30,
	2006		2005	2006	2005
Net crude oil, condensate and gas liquids produced – barrels per day		90,695	111,030	94,365	109,892
United States		23,421	32,631	24,951	32,723
Canada – light		426	523	419	583
– heavy		13,429	11,340	14,300	11,148
– offshore		13,409	25,036	15,931	25,020
– synthetic		10,898	11,562	10,520	9,689
United Kingdom		8,499	9,653	8,301	9,181
Malaysia		12,229	12,740	11,589	13,954
Ecuador		8,384	7,545	8,354	7,594

Net crude oil, condensate and gas liquids sold – barrels per day		103,360	114,526	102,090	111,727
United States		23,421	32,631	24,951	32,723
Canada – light		426	523	419	583
– heavy		13,429	11,340	14,300	11,148
– offshore		15,645	24,769	17,595	24,459
– synthetic		10,898	11,562	10,520	9,689
United Kingdom		9,896	10,352	8,854	9,295
Malaysia		12,952	15,948	13,271	15,912
Ecuador (1)		16,693	7,401	12,180	7,918

Net natural gas sold – thousands of cubic feet per day		87,466	106,908	85,539	109,689
United States		68,691	89,223	64,159	90,006
Canada		9,435	10,599	9,767	11,222
United Kingdom		9,340	7,086	11,613	8,461

Total net hydrocarbons produced – equivalent barrels per day (2)		105,273	128,848	108,621	128,174
Total net hydrocarbons sold – equivalent barrels per day (2)		117,938	132,344	116,346	130,009

Weighted average sales prices – Crude oil and condensate – dollars per barrel (3)
United States	$	61.04	44.57	57.38	43.46
Canada (4) – light		64.05	50.22	57.28	48.41
– heavy (5)		32.44	17.42	24.65	16.08
– offshore		67.43	49.32	63.12	46.52
– synthetic		69.16	53.95	64.78	53.36
United Kingdom		69.85	48.14	65.91	47.95
Malaysia (6)		56.81	41.93	53.68	42.61
Ecuador (7)		28.09	33.71	31.33	30.03

Natural gas – dollars per thousand cubic feet
United States (3)	$	7.28	7.37	8.32	7.08
Canada (4)		5.76	6.26	7.17	6.17
United Kingdom (4)		7.15	4.38	7.61	5.02

(1)	Includes settlement with nonoperator partners of 9,375 barrels per day in the second quarter of 2006 and 4,714 barrels per day in the first six months of 2006 for Block 16 crude oil withheld from the Company since 2004.

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

(3)	Includes intracompany transfers at market prices.

(4)	U.S. dollar equivalent.

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

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

(7)	The quarter and year-to-date 2006 prices are adversely affected by the partial settlement with nonoperator partners of crude oil production owed to the Company since 2004 and a revenue sharing with the Ecuadorian government that was effective in April 2006.

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

OIL AND GAS OPERATING RESULTS


(Millions of dollars)	United States		Canada		United Kingdom		Ecuador	Malaysia	Other		Synthetic Oil – Canada		Total
Three Months Ended June 30, 2006
Oil and gas sales and other revenues	$	177.4	143.4		69.1		42.7	67.1	.9		68.5		569.1
Production expenses		21.3	28.4		5.0		11.0	9.1	—		31.6		106.4
Depreciation, depletion and amortization		24.6	24.9		7.8		9.0	12.5	.1		3.8		82.7
Accretion of asset retirement obligations		.7	1.0		.5		—	—	.1		.2		2.5
Net costs associated with hurricanes		.8	—		—		—	—	—		—		.8
Exploration expenses
Dry holes		3.5	—		—		—	.7	(.1	)	—		4.1
Geological and geophysical		9.4	(.2	)	—		—	5.8	.1		—		15.1
Other		3.4	.2		.2		—	—	1.6		—		5.4

		16.3	—		.2		—	6.5	1.6		—		24.6
Undeveloped lease amortization		4.4	.9		—		—	—	.3		—		5.6

Total exploration expenses		20.7	.9		.2		—	6.5	1.9		—		30.2

Selling and general expenses		4.8	2.8		1.1		.4	1.0	3.3		.2		13.6
Income tax provisions (benefits)		36.7	8.6		22.0		8.9	16.1	.3		(4.7	)	87.9

Results of operations (excluding corporate overhead and interest)	$	67.8	76.8		32.5		13.4	21.9	(4.8	)	37.4		245.0

Three Months Ended June 30, 2005
Oil and gas sales and other revenues	$	366.8	136.9		48.5		22.7	60.9	.9		56.8		693.5
Production expenses		26.8	14.2		4.3		5.2	10.4	—		22.0		82.9
Depreciation, depletion and amortization		26.5	31.5		7.6		4.9	13.9	.1		3.1		87.6
Accretion of asset retirement obligations		.9	.9		.4		—	—	.1		.2		2.5
Exploration expenses
Dry holes		1.0	(.7	)	(.1	)	—	6.7	1.9		—		8.8
Geological and geophysical		4.6	1.3		—		—	14.7	1.6		—		22.2
Other		2.8	.2		.2		—	—	.7		—		3.9

		8.4	.8		.1		—	21.4	4.2		—		34.9
Undeveloped lease amortization		4.0	.7		—		—	—	.4		—		5.1

Total exploration expenses		12.4	1.5		.1		—	21.4	4.6		—		40.0

Selling and general expenses		5.2	2.1		.8		.4	1.9	2.7		.1		13.2
Income tax provisions		107.1	29.2		14.6		4.9	11.1	.2		10.3		177.4

Results of operations (excluding corporate overhead and interest)	$	187.9	57.5		20.7		7.3	2.2	(6.8	)	21.1		289.9

Six Months Ended June 30, 2006
Oil and gas sales and other revenues	$	375.3	281.5		121.9		69.1	121.1	2.1		123.3		1,094.3
Production expenses		36.9	48.2		9.5		17.6	17.4	—		62.3		191.9
Depreciation, depletion and amortization		48.0	54.3		14.5		14.5	25.2	.2		7.3		164.0
Accretion of asset retirement obligations		1.4	2.0		.9		—	.1	.3		.3		5.0
Net costs associated with hurricanes		1.3	—		—		—	—	—		—		1.3
Exploration expenses
Dry holes		6.1	—		—		1.1	30.6	3.4		—		41.2
Geological and geophysical		21.1	(.1	)	—		—	12.1	.7		—		33.8
Other		3.9	.3		.2		—	.2	2.8		—		7.4

		31.1	.2		.2		1.1	42.9	6.9		—		82.4
Undeveloped lease amortization		8.5	1.8		—		—	—	.7		—		11.0

Total exploration expenses		39.6	2.0		.2		1.1	42.9	7.6		—		93.4

Selling and general expenses		10.3	5.3		2.0		.6	3.6	6.1		.4		28.3
Income tax provisions		83.6	38.4		38.1		14.2	26.9	.5		2.1		203.8

Results of operations (excluding corporate overhead and interest)	$	154.2	131.3		56.7		21.1	5.0	(12.6	)	50.9		406.6

Six Months Ended June 30, 2005
Oil and gas sales and other revenues	$	549.5	255.7		88.8		43.0	123.0	1.8		93.6		1,155.4
Production expenses		50.8	28.1		8.0		10.9	17.2	—		42.6		157.6
Depreciation, depletion and amortization		52.8	63.3		13.5		9.4	26.2	.1		6.0		171.3
Accretion of asset retirement obligations		2.0	1.7		.8		—	.1	.2		.3		5.1
Exploration expenses
Dry holes		16.6	(.7	)	(.1	)	—	21.7	22.6		—		60.1
Geological and geophysical		12.7	1.6		—		—	16.3	1.6		—		32.2
Other		3.5	.3		.3		—	—	1.8		—		5.9

		32.8	1.2		.2		—	38.0	26.0		—		98.2
Undeveloped lease amortization		9.8	1.5		—		—	—	.8		—		12.1

Total exploration expenses		42.6	2.7		.2		—	38.0	26.8		—		110.3

Selling and general expenses		9.4	4.4		1.7		.5	4.0	5.3		.3		25.6
Income tax provisions		142.1	51.4		26.9		9.7	25.6	.5		14.5		270.7

Results of operations (excluding corporate overhead and interest)	$	249.8	104.1		37.7		12.5	11.9	(31.1	)	29.9		414.8

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

Results of Operations (Contd.)

Refining and Marketing

Results of refining and marketing operations are presented below by geographic segment.


	Income (Loss)
	Three Months Ended June 30,				Six Months Ended June 30,
(Millions of dollars)	2006			2005	2006		2005
Refining and marketing
North America	$	(26.3	)	59.7	(63.4	)	51.4
United Kingdom		13.1		7.7	12.9		10.5

Total	$	(13.2	)	67.4	(50.5	)	61.9

Refining and marketing operations in North America incurred a loss of $26.3 million during the second quarter of 2006 compared to earnings of $59.7 million in the same period a year ago. The Meraux refinery was down for repairs following Hurricane Katrina for a portion of the 2006 quarter prior to restarting in May. The earnings decline in the 2006 quarter was mostly due to downtime at Meraux and $26.5 million in unrecoverable Hurricane Katrina-related repair costs at this refinery. Income in the 2005 quarter benefited from strong margins at the Meraux refinery. Earnings in the United Kingdom were $13.1 million in the second quarter of 2006 compared to earnings of $7.7 million in the same period a year ago. The 2006 period benefited from higher petroleum products sold and lower maintenance costs due to the Milford Haven refinery undergoing a full turnaround in the 2005 period. Worldwide petroleum product sales averaged 363,109 barrels per day in 2006, compared to 354,342 barrels per day in the same period in 2005. Worldwide refinery inputs were 90,832 barrels per day in the second quarter of 2006 compared to 176,218 in the 2005 quarter; inputs in 2006 were adversely affected by the Meraux refinery downtime partially offset by Milford Haven being fully operational in the 2006 period versus partial downtime for turnaround in the second quarter 2005.

Refining and marketing operations in North America in the first half of 2006 incurred a loss of $63.4 million compared to income of $51.4 million in the 2005 period. Current year results were unfavorable mostly due to downtime and repair costs at the Meraux refinery following Hurricane Katrina. Meraux incurred $39.5 million of repair costs during the period which are not expected to be recoverable from insurance. Results in the United Kingdom reflected earnings of $12.9 million in the six months ended June 30, 2006 compared to earnings of $10.5 million in 2005. The increase was primarily due to higher volumes of petroleum products sold following the Milford Haven refinery turnaround in the prior year.

Selected operating statistics for the three-month and six-month periods ended June 30, 2006 and 2005 follow.


	Three Months Ended June 30,		Six Months Ended June 30,
	2006	2005	2006	2005
Refinery inputs – barrels per day	90,832	176,218	77,519	179,244
North America	54,904	157,204	44,232	150,510
United Kingdom	35,928	19,014	33,287	28,734

Petroleum products sold – barrels per day	363,109	354,342	349,817	355,681
North America	326,117	330,051	315,313	324,257
Gasoline	262,463	225,158	254,672	218,032
Kerosine	1,681	5,699	2,955	8,272
Diesel and home heating oils	47,121	70,730	47,155	69,686
Residuals	9,148	20,178	5,937	21,678
Asphalt, LPG and other	5,704	8,286	4,594	6,589
United Kingdom	36,992	24,291	34,504	31,424
Gasoline	12,072	10,176	11,953	10,305
Kerosine	2,796	1,348	3,047	2,086
Diesel and home heating oils	13,117	10,984	11,347	14,229
Residuals	5,103	1,165	4,124	2,742
LPG and other	3,904	618	4,033	2,062

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

Results of Operations (Contd.)

Corporate and other

The net cost of corporate activities, which include interest income and expense and corporate overhead not allocated to operating functions, was $17.8 million in the current quarter compared to $9.6 million in the 2005 quarter with the cost increase due to unfavorable foreign currency exchange effects and higher compensation costs in 2006. In the first six months of 2006, corporate activities reflected a net cost of $28.2 million compared to a net cost of $15.8 million a year ago. Unfavorable foreign currency exchange results and higher share-based compensation expense accounted for most of the higher net costs in 2006.

Financial Condition

Net cash provided by operating activities was $184.0 million for the first six months of 2006 compared to $452.4 million for the same period in 2005. The decline in 2006 was primarily attributable to changes in other operating working capital. Changes in operating working capital other than cash and cash equivalents used cash of $393.7 million in the first six months of 2006 and $102.5 million in the first six months of 2005. In the 2006 period accounts receivable increased due to higher product prices and Meraux refinery repair costs expected to be recovered from insurance. Inventories of crude oil increased significantly due to building stocks at the Meraux refinery associated with restart of crude throughput in the second quarter 2006. Finished product inventories increased due to higher prices and higher volumes held in inventory at the end of the second quarter of 2006. Prepaid expenses increased due to higher property insurance premiums and timing of income tax payments. Accounts payable and accrued liabilities increased primarily due to higher amounts owed on crude oil purchases. Cash from operating activities was reduced by expenditures for major repairs and asset retirements totaling $10.6 million in the first six months of 2006 and $27.8 million in 2005, with the 2005 amount mostly attributable to a full plant-wide turnaround at the Milford Haven, Wales refinery. Proceeds from the sale of assets provided cash of $12.2 million in the first six months of 2006 compared to $160.4 million in the same period in 2005.

Other predominant uses of cash in each year were for dividends, which totaled $42.0 million in 2006 and $41.5 million in 2005 and for capital expenditures, which including amounts expensed, are summarized in the following table.


	Six Months Ended June 30,
(Millions of dollars)	2006			2005
Capital Expenditures
Exploration and production	$	555.8		481.7
Refining and marketing		92.5		120.9
Corporate and other		3.4		11.9

Total capital expenditures		651.7		614.5
Geological, geophysical and other exploration expenses charged to income		(41.2	)	(38.1	)

Total property additions and dry holes	$	610.5		576.4

Working capital (total current assets less total current liabilities) at June 30, 2006 was $774.8 million, up $222.9 million from December 31, 2005. This level of working capital includes carrying certain inventories using lower historical costs under LIFO accounting. The carrying value of these inventories was $509.5 million below current costs at June 30, 2006. Explanations for the increase in working capital in 2006 can be found in the second preceding paragraph.

At June 30, 2006, long-term notes payable of $868.0 million was up $270.1 million from December 31, 2005. Long-term nonrecourse debt of a subsidiary was $7.5 million, down $4.1 million from December 31, 2005, primarily due to repayments. A summary of capital employed at June 30, 2006 and December 31, 2005 follows.


	June 30, 2006			Dec. 31, 2005
(Millions of dollars)	Amount		%	Amount		%
Capital Employed
Notes payable	$	868.0	18.4	$	597.9	14.7
Nonrecourse debt of a subsidiary		7.5	0.1		11.6	0.3
Stockholders’ equity		3,846.2	81.5		3,461.0	85.0

Total capital employed	$	4,721.7	100.0	$	4,070.5	100.0

As of July 31, 2006, the Company’s long-term debt rating by Moody’s Investors Service was “Baa2” and by Standard & Poor’s was “BBB”. The Company’s ratio of earnings to fixed charges was 18.6 to 1 for the six months ended June 30, 2006.

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

Financial Condition (Contd.)

Accounting and Other Matters

In September 2005, the Emerging Issues Task Force (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 has been applied to new arrangements entered into beginning April 1, 2006, and will be applied to all inventory transactions that are completed after December 15, 2006 for arrangements entered into prior to March 15, 2006. The adoption of this consensus in the second quarter 2006 did not have a significant impact on the Company’s financial statements.

In March 2005, the EITF decided in Issue 04-6 that mining operations should account for post-production stripping costs as a variable production cost that should be considered a component of mineral inventory costs. The Company’s synthetic oil 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.

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 June 30, 2006, the Company has a receivable of approximately $17.7 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.

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

Outlook

Crude oil prices briefly touched record levels in July 2006, but these prices have since retreated slightly from these highs. The Company expects its oil and natural gas production in the third quarter of 2006 to average 90,000 barrels of oil equivalent per day compared to about 105,000 barrels of oil equivalent per day in the second quarter of 2006. Sales volumes in the third quarter of 2006 are expected to be 83,000 barrels of oil equivalent per day. Total Company production for the full year of 2006 is anticipated to average between 100,000 and 105,000 barrels of oil equivalent per day. The production decline in the third quarter is attributable to a shut down for major maintenance at Terra Nova until October 2006, lower production in the deepwater Gulf of Mexico primarily due to anticipated storm and other downtime, less heavy oil production in Canada due to a fire at a non-operated battery at Seal and partial downtime for planned maintenance at fields in the U.K. North Sea. The Company’s share of maintenance expense for the Terra Nova project is anticipated to be about $8 million in the third quarter. The Meraux refinery has restarted and is nearing normal operations. Further expense of about $10 - $15 million is projected for the third quarter 2006 associated with repair costs at Meraux that is not anticipated to be recoverable from insurance policies. On July 19, the U.K. government enacted a 10% income tax rate increase for E&P companies, retroactive to the beginning of 2006, that will increase the Company’s effective E&P tax rate in this country from 40% to 50%. The Company will recognize a charge of approximately $18 million in the third quarter 2006 associated with this tax rate increase, including a higher tax impact for the first six months of 2006 of $7 million. The Company currently anticipates total capital expenditures in 2006 of approximately $1.6 billion. On August 2, 2006 the Company’s Board of Directors declared a quarterly divided of $.15 per Common share ($.60 per Common share on an annualized basis), a 33.3% increase from the previous quarterly dividend.

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 G to this Form 10-Q report, Murphy makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.

Murphy was a party to natural gas price swap agreements at June 30, 2006 for a remaining notional volume of 0.4 million MMBTU that are intended to hedge the financial exposure of its Meraux, Louisiana refinery to fluctuations in the future price of a portion of natural gas to be purchased for fuel in 2006. In each month of settlement, the swaps require Murphy to pay an average natural gas price of $3.35 per MMBTU and to receive the average NYMEX price for the final three trading days of the month. At June 30, 2006, the estimated fair value of these agreements was recorded as an asset of $1.4 million. A 10% increase in the average NYMEX price of natural gas would have increased this asset by $0.2 million, while a 10% decrease would have reduced the asset by a similar amount.

At June 30, 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 June 30, 2006, the estimated fair value of these agreements was recorded as a $21.0 million liability. A 10% increase in the price of Canadian heavy oil at the Hardisty terminal in Canada would have increased this liability by $2.0 million, while a 10% decrease would have decreased this liability by a similar amount.

ITEM 4. CONTROLS AND PROCEDURES

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

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

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

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

PART II – OTHER INFORMATION (Contd.)

ITEM 1. LEGAL PROCEEDINGS (Contd.)

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 was held in the second quarter 2006, but no decision has been issued. 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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

At the annual meeting of security holders on May 10, 2006, the directors proposed by management were elected with a tabulation of votes to the nearest share as shown below.


	For	Withheld
Frank W. Blue	174,620,886	2,628,861
George S. Dembroski	174,290,831	2,958,916
Claiborne P. Deming	174,234,791	3,014,956
Robert A. Hermes	171,176,379	6,073,367
R. Madison Murphy	159,793,488	17,456,259
William C. Nolan Jr.	173,379,136	3,870,611
Ivar B. Ramberg	174,620,316	2,629,431
Neal E. Schmale	174,619,161	2,630,586
David J. H. Smith	174,618,581	2,631,166
Caroline G. Theus	174,008,685	3,241,061

The earlier appointment by the Audit Committee of the Board of Directors of KPMG LLP as independent auditors for 2006 was approved with 175,879,957 shares voted in favor, 556,082 shares voted in opposition and 813,705 shares not voted.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)	The Exhibit Index on page 30 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.

(b)	A report on Form 8-K was filed on April 25, 2006 that included a News Release announcing the Company’s earnings and certain other financial information for the three-month period ended March 31, 2006.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


*MURPHY OIL CORPORATION*
(Registrant)

By		/s/ JOHN W. ECKART
		John W. Eckart, Controller
		(Chief Accounting Officer and Duly Authorized Officer)

August 4, 2006

(Date)

EXHIBIT INDEX


Exhibit No.
3.2*		By-Laws of Murphy Oil Corporation as amended effective August 2, 2006

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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