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 September 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 September 30, 2006 was 187,057,469.

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		20

Item 3. Quantitative and Qualitative Disclosures About Market Risk		31

Item 4. Controls and Procedures		31

Part II – Other Information

Item 1. Legal Proceedings		32

Item 1A. Risk Factors		33

Item 6. Exhibits and reports on Form 8-K		33

Signature		34

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)


	(Unaudited) September 30, 2006			December 31, 2005
ASSETS
Current assets
Cash and cash equivalents	$	469,353		585,333
Accounts receivable, less allowance for doubtful accounts of $15,109 in 2006 and $14,508 in 2005		1,039,026		865,155
Inventories, at lower of cost or market
Crude oil and blend stocks		188,673		83,265
Finished products		181,372		146,753
Materials and supplies		102,544		84,937
Prepaid expenses		147,918		33,239
Deferred income taxes		42,285		40,264

Total current assets		2,171,171		1,838,946

Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $2,802,965 in 2006 and $2,459,022 in 2005		4,964,362		4,374,229
Goodwill, net		45,963		44,206
Deferred charges and other assets		164,847		111,130

Total assets	$	7,346,343		6,368,511

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	4,659		4,490
Accounts payable and accrued liabilities		1,293,762		1,176,634
Income taxes payable		130,630		105,884

Total current liabilities		1,429,051		1,287,008

Notes payable		782,076		597,926
Nonrecourse debt of a subsidiary		7,458		11,648
Deferred income taxes		620,157		614,091
Asset retirement obligations		198,733		176,823
Accrued major repair costs		68,155		55,350
Deferred credits and other liabilities		175,929		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 187,150,783 shares in 2006 and 186,828,618 shares in 2005		187,151		186,829
Capital in excess of par value		441,387		437,963
Retained earnings		3,224,940		2,744,274
Accumulated other comprehensive income		213,738		131,324
Unamortized restricted stock awards		—		(16,410	)
Treasury stock, 93,314 shares of Common Stock in 2006 and 881,940 shares in 2005, at cost		(2,432	)	(22,990	)

Total stockholders’ equity		4,064,784		3,460,990

Total liabilities and stockholders’ equity	$	7,346,343		6,368,511

See Notes to Consolidated Financial Statements on page 7.

The Exhibit Index is on page 35.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

(Thousands of dollars except per share amounts)


	Three Months Ended September 30,					Nine Months Ended September 30,
	2006			2005		2006		2005
REVENUES
Sales and other operating revenues	$	4,147,706		3,311,332		10,932,857		8,487,045
Gain (loss) on sale of assets		432		6,247		(941	)	178,171
Interest and other income (loss)		5,284		(660	)	11,687		16,517

Total revenues		4,153,422		3,316,919		10,943,603		8,681,733

COSTS AND EXPENSES
Crude oil and product purchases		3,275,816		2,546,896		8,580,267		6,302,891
Operating expenses		284,375		210,605		799,369		641,035
Exploration expenses, including undeveloped lease amortization		35,970		32,863		129,406		143,168
Selling and general expenses		52,251		41,091		139,282		117,855
Depreciation, depletion and amortization		87,181		93,769		286,745		307,562
Net costs associated with hurricanes		27,160		34,054		105,933		34,054
Accretion of asset retirement obligations		2,614		2,271		7,690		7,403
Interest expense		17,021		12,238		39,262		35,775
Interest capitalized		(11,284	)	(10,834	)	(29,912	)	(27,156	)

Total costs and expenses		3,771,104		2,962,953		10,058,042		7,562,587

Income from continuing operations before income taxes		382,318		353,966		885,561		1,119,146
Income tax expense		159,543		131,567		334,839		435,801

Income from continuing operations		222,775		222,399		550,722		683,345
Income from discontinued operations, net of tax		—		8,549		—		8,549

NET INCOME	$	222,775		230,948		550,722		691,894

INCOME PER COMMON SHARE – BASIC
Income from continuing operations	$	1.20		1.20		2.96		3.71
Income from discontinued operations		—		.05		—		.05

NET INCOME – BASIC	$	1.20		1.25		2.96		3.76

INCOME PER COMMON SHARE – DILUTED
Income from continuing operations	$	1.18		1.18		2.91		3.64
Income from discontinued operations		—		.05		—		.05

NET INCOME – DILUTED	$	1.18		1.23		2.91		3.69

Average common shares outstanding – basic		186,211,753		184,355,365		185,948,743		184,083,392
Average common shares outstanding – diluted		189,238,922		188,069,208		189,067,278		187,740,260

See Notes to Consolidated Financial Statements on page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

(Thousands of dollars)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
Net income	$	222,775	230,948		550,722		691,894

Other comprehensive income, net of tax
Cash flow hedges
Net derivative gains (losses)		3,329	(2,716	)	(5,508	)	(22,017	)
Reclassification adjustments		6,646	(246	)	15,598		(950	)

Total cash flow hedges		9,975	(2,962	)	10,090		(22,967	)
Minimum pension liability adjustment		—	—		13		—
Net gain from foreign currency translation		1,806	33,393		72,311		18,889

COMPREHENSIVE INCOME	$	234,556	261,379		633,136		687,816

See Notes to Consolidated Financial Statements on page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)


	Nine Months Ended September 30,
	2006			2005*
OPERATING ACTIVITIES
Net income	$	550,722		691,894
Less income from discontinued operations		—		8,549

Income from continuing operations		550,722		683,345
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Depreciation, depletion and amortization		286,745		307,562
Provisions for major repairs		22,296		27,310
Expenditures for major repairs and asset retirement obligations		(13,142	)	(30,249	)
Dry hole costs		41,885		63,992
Amortization of undeveloped leases		16,717		17,519
Accretion of asset retirement obligations		7,690		7,403
Deferred and noncurrent income tax charges		13,972		20,077
Pretax losses (gains) from disposition of assets		941		(178,171	)
Net increase in noncash operating working capital		(306,331	)	(150,929	)
Other		(7,084	)	(6,688	)

Net cash provided by continuing operations		614,411		761,171
Net cash provided by discontinued operations		—		8,549

Net cash provided by operating activities		614,411		769,720

INVESTING ACTIVITIES
Property additions and dry hole costs		(884,144	)	(881,130	)
Proceeds from sales of assets		19,796		173,629
Proceeds from maturities of marketable securities		—		17,892
Other – net		(8,417	)	(5,222	)

Net cash required by investing activities		(872,765	)	(694,831	)

FINANCING ACTIVITIES
Increase (decrease) in notes payable		183,989		(29,065	)
Decrease in nonrecourse debt of a subsidiary		(4,667	)	(4,193	)
Proceeds from exercise of stock options and employee stock purchase plans		15,354		18,731
Excess tax benefits related to exercise of stock options		7,057		–
Cash dividends paid		(70,056	)	(62,305	)
Other		—		(1,052	)

Net cash provided by (used in) financing activities		131,677		(77,884	)

Effect of exchange rate changes on cash and cash equivalents		10,697		(875	)

Net decrease in cash and cash equivalents		(115,980	)	(3,870	)
Cash and cash equivalents at January 1		585,333		535,525

Cash and cash equivalents at September 30	$	469,353		531,655

SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid, net of refunds	$	372,277		467,676

Interest capitalized in excess of interest paid		3,066		3,591

*	Revised to reconcile Net cash provided by operating activities to Net income. Totals presented in 2005 for Net cash provided by operating activities, Net cash required by investing activities and Net cash provided by (used in) financing activities are unchanged by this revision in presentation.

See Notes to Consolidated Financial Statements on page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

(Thousands of dollars)


	Nine Months Ended September 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 187,150,783 shares in 2006 and 186,828,618 shares in 2005
Balance at beginning of period	$	186,829		94,613
Exercise of stock options		322		—
Two-for-one stock split effective June 3, 2005		—		92,216

Balance at end of period		187,151		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		9,720		1,273
Restricted stock transactions and other		(7,464	)	14,435
Amortization, forfeitures and other		17,169		–
Sale of stock under employee stock purchase plans		409		562
Two-for-one stock split effective June 3, 2005		—		(92,216	)
Reclassification from Unamortized Restricted Stock Awards upon adoption of SFAS No. 123R		(16,410	)	—

Balance at end of period		441,387		435,099

Retained Earnings
Balance at beginning of period		2,744,274		1,981,020
Net income for the period		550,722		691,894
Cash dividends		(70,056	)	(62,305	)

Balance at end of period		3,224,940		2,610,609

Accumulated Other Comprehensive Income
Balance at beginning of period		131,324		134,509
Foreign currency translation gains, net of taxes		72,311		18,889
Cash flow hedging gains (losses), net of taxes		10,090		(22,967	)
Minimum pension liability adjustment, net of taxes		13		—

Balance at end of period		213,738		130,431

Unamortized Restricted Stock Awards
Balance at beginning of period		(16,410	)	(4,738	)
Reclassification to Capital in Excess of Par upon adoption of SFAS No. 123R		16,410		–
Stock awards		—		(16,344	)
Amortization, forfeitures and other		—		3,895

Balance at end of period		—		(17,187	)

Treasury Stock
Balance at beginning of period		(22,990	)	(67,293	)
Exercise of stock options		13,345		28,584
Sale of stock under employee stock purchase plans		501		550
Awarded restricted stock, net of forfeitures		6,712		4,332

Balance at end of period		(2,432	)	(33,827	)

Total Stockholders’ Equity	$	4,064,784		3,311,954

See notes to consolidated financial statements on 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 September 30, 2006, and the results of operations, cash flows and changes in stockholders’ equity for the three-month and nine-month periods ended September 30, 2006 and 2005, in conformity with accounting principles generally accepted in the United States of America. 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 three months and nine months ended September 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 September 30, 2006, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $349.5 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 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		155,381		133,911
Reclassification to proved properties		(77,683	)	—
Capitalized costs charged to expense		(3,431	)	—

Ending balance at September 30	$	349,523		240,016

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	$	161,635	151,640
Capitalized exploratory well costs capitalized for more than one year		187,888	88,376

Balance at September 30	$	349,523	240,016

Number of projects that have exploratory well costs that have been capitalized for more than one year		11	7

Of the $187.9 million of exploratory well costs capitalized for more than one year, $6.9 million is in the U.S., $159.5 million is in Malaysia, $5.7 million is in Canada and $15.8 million is in the Republic of Congo. The U.S. amount relates to a deepwater Gulf of Mexico well that is pending development. 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note B – Property, Plant and Equipment (Contd.)

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 2,600 barrels of oil equivalent per day during the nine-month period ended September 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. In September 2005, the Company’s Canadian subsidiary sold an existing heavy oil field in the Winter area and recorded a $6 million pretax gain on this transaction. Both transactions are included in Gain on Sale of Assets on the Consolidated Statement of Income in the respective periods inclusive of the sale transaction.

In the third quarter of 2005, the Company’s Canadian subsidiary recorded an $8.6 million income tax benefit associated with the sale of Western Canadian assets in 2004. The benefit was the result of a change in a previous estimate and has been reported as Income from Discontinued Operations on the Consolidated Income Statement.

Note C – Employee and Retiree Pension and Postretirement Plans

The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors’ plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors unfunded health care and life insurance benefit plans 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 nine-month periods ended September 30, 2006 and 2005.


	Three Months Ended September 30,
	2006			2005		2006		2005
(Thousands of dollars)	Pension Benefits					Postretirement Benefits
Service cost	$	2,519		2,418		566		460
Interest cost		5,314		5,404		1,006		940
Expected return on plan assets		(4,959	)	(4,974	)	—		—
Amortization of prior service cost		380		59		(69	)	(68	)
Amortization of transitional asset		(163	)	(4	)	—		—
Recognized actuarial loss		1,606		1,689		446		435

Net periodic benefit expense	$	4,697		4,592		1,949		1,767


	Nine Months Ended September 30,
	2006			2005		2006		2005
(Thousands of dollars)	Pension Benefits					Postretirement Benefits
Service cost	$	7,991		6,997		1,698		1,400
Interest cost		16,332		15,033		3,018		2,714
Expected return on plan assets		(15,411	)	(14,121	)	—		—
Amortization of prior service cost		1,142		177		(207	)	(203	)
Amortization of transitional asset		(481	)	(36	)	—		—
Recognized actuarial loss		4,772		4,208		1,338		1,119

Net periodic benefit expense	$	14,345		12,258		5,847		5,030

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 nine-month period ended September 30, 2006, the Company made contributions to its domestic and foreign defined benefit pension and postretirement plans of $8.1 million and remaining funding in 2006 for these plans is currently anticipated to be $3.0 million.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C – Employee and Retiree Pension and Postretirement Plans (Contd.)

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 $1.2 million and $1.0 million in estimated benefits related to the Act in the nine-month periods ended September 30, 2006 and 2005, respectively.

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 September 30, 2006 and 2005 were $2.5 million and $3.4 million, respectively. Related income tax benefits recognized in the income statement for the three-month periods ended September 30, 2006 and 2005 were $0.9 million and $1.2 million, respectively. Compensation costs charged against income for share-based plans during the nine-month periods ended September 30, 2006 and 2005 were $16.4 million and $9.6 million, respectively. The related income tax benefits recognized in the income statement in these nine-month periods of 2006 and 2005 were $5.7 million and $3.4 million, respectively.

As of September 30, 2006, there was $35.9 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 nine-month periods ended September 30, 2006 and 2005 was $15.4 million and $18.7 million, respectively. The actual income tax benefits realized for the tax deductions from option exercises of the share-based payment arrangements totaled $8.6 million and $12.1 million for the nine-month periods ended September 30, 2006 and 2005, respectively.

The Company had 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – Incentive Plans (Contd.)

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 nine-month periods ended September 30, 2005, would have been the pro forma amounts shown in the following table.


(Thousands of dollars except per share data)	Three Months Ended Sept. 30, 2005			Nine Months Ended Sept. 30, 2005
Net income – As reported	$	230,948		691,894
Restricted stock compensation expense included in income, net of tax		1,471		4,044
Total stock-based compensation expense using fair value method for all awards, net of tax		(2,330	)	(7,913	)

Net income – Pro forma	$	230,089		688,025

Net income per share – As reported, basic	$	1.25		3.76
Pro forma, basic		1.25		3.74
As reported, diluted		1.23		3.69
Pro forma, diluted		1.22		3.66

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 nine-month periods ended September 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	(834,102	)		17.38	(1,096,537	)		16.08
Forfeitures and other	(113,000	)		44.75	(69,880	)		14.04

Outstanding at September 30	8,255,035		$	25.44	8,806,163		$	21.64

Exercisable at September 30	6,107,881		$	18.23	5,956,603		$	16.40

The total intrinsic value of stock options exercised during the nine-month periods ended September 30, 2006 and 2005 was $31.4 million and $42.1 million, respectively.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – Incentive Plans (Contd.)

Additional information about stock options outstanding at September 30, 2006 and 2005 is shown below.


	Options Outstanding				Options Exercisable
	No. of Shares	Avg. Life in Years	Aggregate Intrinsic Value ($000)		No. of Shares	Avg. Life in Years	Aggregate Intrinsic Value ($000)
Sept. 30, 2006	8,255,035	4.7	$	189,927	6,107,881	4.4	$	179,086
Sept. 30, 2005	8,806,163	5.6		248,635	5,956,603	5.4		199,355

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 nine-month periods ended September 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	(28,834	)	(14,555	)

Balance at September 30	715,361		478,445

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

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	20,568	22,950

Balance at September 30	56,142	35,574

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – Incentive Plans (Contd.)

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 19,205 shares at an average price of $47.35 per share in the nine-month period ended September 30, 2006 and 24,871 shares at $42.76 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 September 30, 2006, 130,280 shares remained available for sale under the ESPP. The fair value per share of the ESPP was approximately $7.81 for the nine-month period ended September 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 nine-month periods ended September 30, 2006 and 2005. The following table reconciles the weighted-average shares outstanding used for these computations.


	Three Months Ended September 30,		Nine Months Ended September 30,
(Weighted-average shares)	2006	2005	2006	2005
Basic method	186,211,753	184,355,365	185,948,743	184,083,392
Dilutive stock options	3,027,169	3,713,843	3,118,535	3,656,868

Diluted method	189,238,922	188,069,208	189,067,278	187,740,260

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 nine-month periods ended September 30, 2006 but were not included in the computation of diluted EPS because the incremental shares from assumed exercise were antidilutive. There were no antidilutive options for the three-month and nine-month periods ended September 30, 2005.

Note F – Financing Arrangements

In May 2006, Murphy extended its five year committed credit facility with a major banking consortium for one year. In August 2006, the Company and certain wholly-owned subsidiaries increased the borrowing capacity under the credit facility to $1.04 billion through June 2010. The facility permits the same entities to borrow up to $982.5 million through June 2011.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note G – Financial Instruments and Risk Management

Murphy utilizes derivative instruments to manage certain of its 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 September 30, 2006 of 0.2 million MMBTU (million British Thermal Units). Under the natural gas swaps, the Company pays a fixed rate averaging $3.35 per MMBTU and receives a floating rate in each month of settlement based on the average NYMEX price for the final three trading days of the month. Murphy has a risk management control system to monitor natural gas price risk attributable both to forecasted natural gas requirements and to Murphy’s natural gas swaps. The control system involves using analytical techniques, including various correlations of natural gas purchase prices to future prices, to estimate the impact of changes in natural gas fuel prices on Murphy’s cash flows. The fair value of the effective portions of the natural gas swaps and changes thereto is deferred in 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 nine-month periods ended September 30, 2006 and 2005, the Company received approximately $2.2 million and $4.1 million, respectively, for maturing swap agreements. For the three-month and nine-month periods ended September 30, 2006, the income effect from cash flow hedging ineffectiveness for these contracts was insignificant. In September 2005, the Company determined that approximately 0.4 million MMBTU of contracts maturing in 2005 would no longer qualify as a cash flow hedge since the purchase of this gas was no longer anticipated to occur while the Meraux refinery was temporarily idled after Hurricane Katrina. Gains of $1.5 million were recognized in earnings in the third quarter of 2005 as a result of the contracts no longer qualifying as a cash flow hedge.

•

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 for each month and 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. In the nine-month periods ended September 30, 2006 and 2005, cash flow hedging ineffectiveness relating to the crude oil sales swaps was insignificant. During the nine-month periods ended September 30, 2006 and 2005 the Company paid approximately $23.9 million and $3.9 million, respectively, for settlement of maturing forward sale contracts. The fair value of the crude oil sales swaps is 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 three months, the Company expects to reclassify approximately $3.4 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note H – Accumulated Other Comprehensive Income

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


(Thousands of dollars)	September 30, 2006			December 31, 2005
Foreign currency translation gain, net	$	258,033		185,722
Cash flow hedging, net		(3,369	)	(13,459	)
Minimum pension liability, net		(40,926	)	(40,939	)

Accumulated other comprehensive income	$	213,738		131,324

The effect of SFAS Nos. 133/138, Accounting for Derivative Investments and Hedging Activities, increased AOCI for the nine months ended September 30, 2006 by $10.1 million, net of $3.7 million in income taxes, and hedging ineffectiveness decreased income by $0.3 million, net of $0.1 million on taxes. Derivative instruments decreased AOCI for the nine months ended September 30, 2005 by $22.9 million, net of $9.7 million in income taxes, and hedging ineffectiveness increased income by $1.0 million, net of $0.5 million in income taxes. The ineffectiveness was the result of a portion of swaps no longer qualifying as a cash flow hedge (see Note G). The AOCI decrease in the nine-month period ended September 30, 2005 was primarily related to the change in fair value of blended heavy oil forward sales contracts described in Note G.

Note I – Hurricane Related Matters

In the first nine months of 2006 and 2005, the Company recorded pretax expenses, net of anticipated insurance recoveries, of $105.9 million and $34.1 million, respectively, associated with hurricanes that occurred in the United States in 2005. The components of the 2006 costs included $104.2 million at the Meraux refinery and included $50.5 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; $22.6 million for other uninsured incremental expenses incurred and settlement of oil spill class action litigation; and $25.0 million for depreciation and salaries while the refinery was temporarily idled prior to restarting in the second quarter. The components of the 2005 costs, all of which occurred in the third quarter, included $13.8 million for incremental insurance expenses; $3.0 million for uninsured losses within the Company’s insurance deductibles; $8.9 million for voluntary costs for charitable donations related to hurricane relief efforts and additional employee salaries; $5.1 million for depreciation and salaries for the temporarily idled Meraux, Louisiana, refinery; and $3.3 million for other incremental expenses incurred that are not covered by insurance policies. The costs for the respective periods are reported in Net Costs Associated With Hurricanes in the Consolidated Statements of Income. Total amounts receivable from insurers for hurricane-related matters was $307 million at September 30, 2006, of which $263 million was classified as current in the Consolidated Balance Sheet. See Note J for additional information regarding environmental and other contingencies relating to Hurricane Katrina.

The Company maintains insurance coverage related to losses of production and profits for occurrences such as storms, fires and other issues. During the first quarter of 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. In the third quarter and first nine months of 2005, the Company’s U.S. exploration and production operations recorded $7.6 million and $11.2 million, respectively, in business interruption insurance recoveries relating to prior-year hurricanes. The amounts are reported in Sales and Other Operating Revenues in the Consolidated Statements of Income.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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 two Superfund sites. The potential total cost to all parties to perform necessary remedial work at these sites may be substantial. Based on currently available information, the Company believes that it is a de minimis party as to ultimate responsibility at 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 two sites or other Superfund sites. The Company believes that its share of the ultimate costs to clean-up the two Superfund sites will be immaterial and will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

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

On September 9, 2005, a class action lawsuit was filed in federal court in the Eastern District of Louisiana seeking unspecified damages to the class comprised of residents of St. Bernard Parish caused by a release of crude oil at Murphy Oil USA, Inc.’s (a wholly-owned subsidiary of Murphy Oil Corporation) Meraux, Louisiana, refinery as a result of flood 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. On or about September 25, 2006, the Company reached a settlement with class counsel and on October 10, 2006, the court granted preliminary approval of a class action Settlement Agreement and scheduled a Fairness Hearing for January 4, 2007. The majority of the settlement of $330 million will be paid by insurance. The Company recorded an expense of $14 million in the third quarter 2006 related to settlement costs not covered by insurance. As part of the settlement, all properties in the class area will receive a fair and equitable cash payment and will have residual oil cleaned. In addition, the Company will offer to purchase all properties in an agreed area adjacent to the west side of the Meraux refinery; these property purchases and associated remediation will be paid by the Company and are expected to total $55 million. Approximately 100 non-class

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Environmental and Other Contingencies (Contd.)

action suits regarding the oil spill have been filed and remain pending; however, as part of its October 10, 2006, order, the court stayed these actions pending the settlement proceedings and further orders of the court. The Company believes that insurance coverage exists and it does not expect to incur significant costs associated with this litigation. Accordingly, the Company believes the ultimate resolution of the remaining litigation 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. The St. Bernard Parish action has since been removed to federal court. 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. A trial concerning the 25% disputed interest and any remaining issues was held in the second quarter 2006, and, on September 15, 2006, the court of Queen’s Bench of Alberta issued a ruling in the Company’s favor. Predator will not appeal. Based on this ruling, approximately $14.8 million of previously disputed natural gas sales proceeds, plus associated interest thereon, is expected to be collected by Murphy by the end of 2006.

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 September 30, 2006, the Company had contingent liabilities of $8.5 million under a financial guarantee and $111.6 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – Commitments for Drilling Rigs

The Company has entered into contracts to hire various drilling rigs and associated equipment for periods beyond September 30, 2006. These rigs are primarily utilized for deepwater drilling operations in the Gulf of Mexico and Malaysia. Future commitments under these contracts, all of which expire by 2008, total $371.5 million. A significant portion of these costs are expected to be borne by other working interest owners as partners of the Company 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 L – New Accounting Principles and Recent Accounting Pronouncements

In September 2006, the FASB issued FSP AUG AIR-1 which prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities as historically used by the Company. Accordingly, the Company will elect to use the deferral method for accounting for planned major maintenance activities effective January 1, 2007. Under the deferral method, the actual cost of each planned major maintenance activity is deferred and amortized through the next turnaround. Upon implementation the Accrued Major Repair Costs reported on the Consolidated Balance Sheets will be replaced by a non-current asset representing the net unamortized major maintenance cost at the end of each reporting period and this accounting change is expected to cause a one-time increase to retained earnings of the Company. All prior periods financial statements presented will be retrospectively restated upon adoption of this new standard. The Company is currently evaluating this FSP and at this time is unable to quantify the amount of the impact on its financial statements.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements, and where applicable simplifies and codifies related guidance within GAAP and does not require any new fair value measurements. The Statement is effective for fiscal years beginning January 1, 2008. Provisions of the Statement are to be applied prospectively except in limited situations. The Company does not expect the initial adoption of this Statement to have a material impact on its financial statements.

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of SFAS Nos. 87, 88, 106 and 132(R). This statement requires the Company to recognize in its consolidated balance sheet the overfunded or underfunded status of its defined benefit plans as an asset or liability and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. This statement also requires that the Company measure the funded status of a plan as of December 31 rather than September 30 as previously permitted. The Company is required to implement this statement for the fiscal year ending December 31, 2006, except that the transition to a year-end measurement date is not effective until 2008. The Company is in the early stages of evaluating this statement and at the current time is unable to determine the impact on its financial statements.

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 September 2006, the U.S. Securities and Exchange Commission released Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (SAB 108), which provides interpretive guidance on the SEC’s views regarding the process of quantifying materiality of financial statement misstatements. SAB 108 is effective for fiscal years ending after November 15, 2006, with early application for the first interim period ending after November 15, 2006. The Company is in the early stages of evaluating SAB 108 and at the current time is unable to determine the impact on its financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note L – New Accounting Principles and Recent Accounting Pronouncements (Contd.)

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 June 2006, the EITF finalized Issue 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement. The Task Force reached a consensus that this EITF applied to any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to sales, use, value added, and some excise taxes. The EITF concluded that the presentation of taxes within the scope of this issue may be either gross (included in revenues and costs) or net (excluded from revenues and costs) and is an accounting policy decision that should be disclosed by the Company. As previously disclosed in its annual report on Form 10-K, the Company accounts for excise taxes on petroleum products on a net basis.

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 was 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 $2.6 million and $3.1 million in the nine-month periods ended September 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.

Note M – Income Taxes

Income tax expense for the three-month and nine-month periods in 2006 includes a tax charge of $17.8 million related to a 10% tax rate increase on U.K. oil and gas profits retroactive to the beginning of 2006; this charge was partially offset in the same periods by a $7.6 million benefit for an adjustment of estimated prior-period Canadian income taxes. Income tax expense for the nine-month period 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note N – Business Segments


			Three Months Ended September 30, 2006				Three Months Ended September 30, 2005
(Millions of dollars)	Total Assets at Sept. 30, 2006		External Revenues	Inter- segment Revenues	Income (Loss)		External Revenues		Inter- segment Revenues	Income (Loss)
Exploration and production*
United States	$	916.6	157.8	—	63.6		168.0		—	71.3
Canada		1,750.3	129.2	43.4	63.7		211.3		16.5	98.2
United Kingdom		180.6	18.6	—	(12.0	)	40.6		—	15.2
Ecuador		143.0	21.1	—	5.8		30.3		—	13.3
Malaysia		1,221.9	51.2	—	(.6	)	62.4		—	10.6
Other		99.0	1.2	—	(1.7	)	.8		—	(4.0	)

Total		4,311.4	379.1	43.4	118.8		513.4		16.5	204.6

Refining and marketing
North America		2,090.8	3,490.1	—	114.5		2,512.2		—	11.2
United Kingdom		374.5	278.9	—	12.1		292.0		—	20.8

Total		2,465.3	3,769.0	—	126.6		2,804.2		—	32.0

Total operating segments		6,776.7	4,148.1	43.4	245.4		3,317.6		16.5	236.6
Corporate		569.6	5.3	—	(22.6	)	(.7	)	—	(14.2	)

Total from continuing operations		7,346.3	4,153.4	43.4	222.8		3,316.9		16.5	222.4
Discontinued operations		—	—	—	—		—		—	8.6

Total	$	7,346.3	4,153.4	43.4	222.8		3,316.9		16.5	231.0


	Nine Months Ended September 30, 2006					Nine Months Ended September 30, 2005
(Millions of dollars)	External Revenues		Inter- segment Revenues	Income (Loss)		External Revenues	Inter- segment Revenues	Income (Loss)
Exploration and production*
United States	$	533.1	—	217.8		717.5	—	321.1
Canada		486.7	90.7	245.9		534.9	42.2	232.2
United Kingdom		140.5	—	44.7		129.4	—	52.9
Ecuador		90.2	—	26.9		73.3	—	25.8
Malaysia		172.3	—	4.4		185.4	—	22.5
Other		3.3	—	(14.3	)	2.6	—	(35.1	)

Total		1,426.1	90.7	525.4		1,643.1	42.2	619.4

Refining and marketing
North America		8,724.4	—	51.1		6,399.6	—	62.6
United Kingdom		781.7	—	25.0		622.5	—	31.3

Total		9,506.1	—	76.1		7,022.1	—	93.9

Total operating segments		10,932.2	90.7	601.5		8,665.2	42.2	713.3
Corporate		11.4	—	(50.8	)	16.5	—	(30.0	)

Total from continuing operations		10,943.6	90.7	550.7		8,681.7	42.2	683.3
Discontinued operations		—	—	—		—	—	8.6

Total	$	10,943.6	90.7	550.7		8,681.7	42.2	691.9

*	Additional details about results of oil and gas operations are presented in the tables on page 25.

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

Results of Operations

Murphy’s net income in the third quarter of 2006 was $222.8 million, $1.18 per diluted share, compared to net income of $231.0 million, $1.23 per diluted share, in the third quarter of 2005. Higher quarterly profits for the Company’s refining and marketing operations in the just completed 2006 quarter were offset by lower earnings in exploration and production operations and higher after-tax corporate costs. The 2006 third quarter included income tax charges of $17.8 million associated with a 10% tax rate increase on U.K. oil and natural gas profits. The new U.K. statutory tax rate, which was enacted in July 2006 retroactive to the beginning of 2006, now totals 50% on oil and gas profits. Net income in the 2005 third quarter included income from discontinued operations of $8.6 million, $.05 per share, related to an adjustment of income taxes associated with the sale of most of the Company’s conventional oil and gas assets in Western Canada in the second quarter 2004. Net income in the 2006 and 2005 third quarters included pretax costs of $27.2 million and $34.1 million, respectively, associated with hurricanes that occurred in the U.S. during 2005. These costs are net of anticipated insurance recoveries. The costs in 2006 were mostly associated with unrecoverable repair costs at the Meraux, Louisiana refinery and costs associated with settlement of oil spill class action litigation. The 2005 costs included incremental insurance expenses, uninsured losses within the Company’s insurance deductibles, voluntary costs for Company donations and additional employee salaries, and depreciation and salaries for the temporarily idled Meraux refinery.

For the nine months of 2006, net income totaled $550.7 million, $2.91 per diluted share, compared to $691.9 million, $3.69 per diluted share, for the 2005 period. The 2005 nine-month results included income from discontinued operations of $8.6 million, $.05 per share. Murphy’s income by line of business is presented below.


	Income (Loss)
	Three Months Ended September 30,					Nine Months Ended September 30,
(Millions of dollars)	2006			2005		2006		2005
Exploration and production	$	118.8		204.6		525.4		619.4
Refining and marketing		126.6		32.0		76.1		93.9
Corporate		(22.6	)	(14.2	)	(50.8	)	(30.0	)

Income from continuing operations		222.8		222.4		550.7		683.3
Income from discontinued operations		—		8.6		—		8.6

Net income	$	222.8		231.0		550.7		691.9

The Company’s income contribution from continuing exploration and production (E&P) operations was $118.8 million in the third quarter of 2006 compared to $204.6 million in the same quarter of 2005. The lower earnings in 2006 were primarily caused by lower oil production volumes, lower natural gas prices in North America, higher exploration expenses, higher maintenance costs for Terra Nova field equipment, higher revenue sharing with foreign authorities, higher property insurance costs, and income tax charges. These were partly offset by higher sales prices for crude oil and lower E&P hurricane-related costs in 2006. An income tax charge of $17.8 million in the U.K. related to a 10% tax rate increase was partially offset by a $7.6 million benefit related to an adjustment of estimated prior-period taxes in Canada. The Company’s refining and marketing operations generated a quarterly profit of $126.6 million in the 2006 quarter compared to a profit of $32.0 million in the 2005 quarter, with the improved earnings due to higher margins for refining and retail marketing operations in North America, partially offset by higher hurricane-related costs. The after-tax costs of the corporate functions were $22.6 million in the 2006 quarter compared to costs of $14.2 million in the 2005 quarter with the higher net cost due to a combination of higher interest and administrative expenses.

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

Results of Operations (Contd.)

The Company’s exploration and production continuing operations earned $525.4 million in the first nine months of 2006 and $619.4 million in the same period of 2005. The primary reasons for the lower earnings in this business in 2006 were lower crude oil and natural gas sales volumes in the 2006 period, and a $106.8 million after-tax gain in 2005 on the sale of most mature oil and gas properties on the continental shelf of the Gulf of Mexico. Higher crude oil and natural gas sales prices were realized in 2006 compared to 2005. Exploration expenses were $129.4 million in 2006 compared to $143.2 million in 2005 as the prior-year period included unsuccessful drilling costs in the Republic of Congo. The Company’s refining and marketing operations generated a profit of $76.1 million in the first nine months of 2006 compared to a profit of $93.9 million in 2005. The lower 2006 refining and marketing profit was based on higher hurricane-related expenses in the United States and lower margins in the U.K. Corporate after-tax costs were $50.8 million in the first nine months of 2006 compared to $30.0 million in the 2005 period. The Company had higher net interest expense, higher foreign exchange charges and higher administrative expenses in 2006.

More detailed explanations of these variances for the three-month and nine-month periods are presented in the following sections.

Exploration and Production

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


	Income (Loss)
	Three Months Ended September 30,					Nine Months Ended September 30,
(Millions of dollars)	2006			2005		2006		2005
Exploration and production
United States	$	63.6		71.3		217.8		321.1
Canada		63.7		98.2		245.9		232.2
United Kingdom		(12.0	)	15.2		44.7		52.9
Ecuador		5.8		13.3		26.9		25.8
Malaysia		(.6	)	10.6		4.4		22.5
Other		(1.7	)	(4.0	)	(14.3	)	(35.1	)

Total	$	118.8		204.6		525.4		619.4

Exploration and production operations in the United States reported earnings of $63.6 million in the third quarter of 2006 compared to earnings of $71.3 million a year ago. The decline in earnings in 2006 was primarily caused by lower oil sales volumes and lower natural gas sales prices, higher production expenses, higher dry hole costs and after-tax business interruption insurance recoveries of $4.8 million in the 2005 quarter related to prior-year hurricanes. These were partly offset by higher natural gas sales volumes, higher crude oil sales prices and lower hurricane-related costs in 2006. Hurricane-related costs of $7.6 million in the third quarter 2005 consisted mostly of higher insurance costs and employee assistance. Production expenses increased in the 2006 period compared to 2005 primarily due to higher insurance costs.

Continuing operations in Canada earned $63.7 million this quarter compared to $98.2 million a year ago. This decrease was the result of lower crude oil sales volumes due to no sales at the Terra Nova field, offshore Newfoundland, which was shut-in for equipment maintenance during the entire third quarter of 2006, higher maintenance costs at Terra Nova, and lower natural gas sales prices. Favorable variances in 2006 included higher crude oil sales prices, lower depreciation expense due to no sales at the Terra Nova field in the current period, and a $7.6 million benefit related to an adjustment of estimated prior-period income taxes.

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

U.K. operations reported a loss of $12.0 million in the current quarter compared to earnings of $15.2 million in the prior year. The decrease was primarily due to lower crude oil sales volumes and a $17.8 million income tax charge related to a 10% tax rate increase on U.K. oil and gas profits retroactive to the beginning of 2006, partially offset by higher crude oil sales prices and lower dry hole expenses. Oil production in the U.K. was lower in the 2006 third quarter due to more downtime for maintenance at all fields.

Operations in Ecuador earned $5.8 million in the third quarter of 2006 compared to earnings of $13.3 million a year ago. The decline was due to lower crude oil sales prices resulting from revenue sharing with the Ecuadorian government that became effective in April 2006.

Operations in Malaysia reported a loss of $0.6 million in the 2006 period compared to earnings of $10.6 million during the same period in 2005. The decrease in Malaysia was primarily due to lower crude oil sales volumes and higher geological and geophysical expenses in Blocks SK 311 and H, partially offset by higher crude oil sales prices.

Other international operations reported a loss of $1.7 million in the third quarter of 2006 compared to a loss of $4.0 million in the comparable period a year ago. Dry hole expense credits in the Republic of Congo, relating to prior periods, was partially offset by higher geological and geophysical and other exploratory expenses in Indonesia.

On a worldwide basis, the Company’s crude oil and condensate prices averaged $55.50 per barrel in the current quarter compared to $53.15 in the third quarter of 2005. Average crude oil and liquids production was 79,642 barrels per day in the third quarter of 2006 compared to 94,151 barrels per day in the third quarter of 2005. The production decline in 2006 was primarily attributable to no production at the Terra Nova field, offshore Newfoundland, which was shut-in for equipment maintenance during the entire quarter. Terra Nova produced 9,116 barrels per day in the 2005 third quarter. Oil production in the U.K. was also lower in the 2006 period by 1,929 barrels per day mostly due to more downtime for maintenance at all fields, and oil production in the U.S. declined 1,936 barrels per day primarily due to lower volumes produced at the Front Runner field in the Gulf of Mexico. U.S. production in the 2005 third quarter was adversely affected by downtime resulting from Hurricane Katrina. Crude oil sales volumes averaged 73,112 barrels per day in the third quarter 2006 compared to 93,910 barrels per day in the 2005 period. North American natural gas sales prices averaged $6.90 per thousand cubic feet (MCF) in the most recent quarter compared to $8.54 per MCF in the same quarter of 2005. Natural gas sales volumes averaged 74 million cubic feet per day in the third quarter 2006, up 4 million cubic feet per day from the 2005 quarter. The increase in natural gas sales volumes was primarily due to virtually no downtime in the Gulf of Mexico for hurricanes in 2006 compared to significant downtime in 2005.

Operations in the United States for the nine months ended September 30, 2006 produced income of $217.8 million compared to income of $321.1 million in 2005. The decline in 2006 was primarily due to a $106.8 million after-tax gain on sale of most mature oil and gas properties on the continental shelf of the Gulf of Mexico in the 2005 period and lower oil and natural gas sales volumes, partially offset by higher crude oil and natural gas sales prices and lower after-tax costs associated with hurricanes.

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

In the first nine months of 2006, Canadian continuing operations earned $245.9 million compared to $232.2 million a year ago. The current period includes $37.5 million of income tax benefits related to Federal and provincial tax rate reductions that were enacted in the second quarter 2006, along with a $7.6 million benefit relating to an adjustment of estimated prior-period taxes in Canada. Excluding these income tax benefits in 2006, Canadian earnings declined versus the same period in 2005 due primarily to lower offshore crude oil sales volumes. Production expenses increased due to maintenance costs incurred at the Terra Nova field and higher heavy oil and synthetic oil production volumes.

Income in the U.K. for the nine-month period ended September 30, 2006 was $44.7 million compared to $52.9 million a year ago. The decrease was primarily due to $17.8 million in income tax charges associated with a 10% tax rate increase on U.K. oil and natural gas profits and lower crude oil sales volumes partially offset by higher crude oil and natural gas sales prices and lower dry hole expenses.

For the first nine months of 2006, earnings in Ecuador were $26.9 million compared to $25.8 million for the 2005 period. Higher crude oil sales volumes in the 2006 period were virtually offset by lower crude oil sales prices adversely affected by revenue sharing with the Ecuadorian government that was effective in April 2006 and partial settlement with nonoperator partners of crude oil production owed to the Company since 2004.

Malaysia operations earned $4.4 million in the 2006 period compared to $22.5 million a year ago. The decrease in 2006 earnings was primarily due to lower crude oil sales volumes and higher exploration expenses, partially offset by higher crude oil sales prices.

Other international operations reported a loss of $14.3 million in the first nine months of 2006 compared to a loss of $35.1 million in the 2005 period. Lower dry hole expense in the Republic of Congo was the primary cause of the variance between periods.

For the nine-month period ended September 30, 2006, the Company’s sales price for crude oil and condensate averaged $52.80 per barrel compared to $45.15 per barrel in the same period of 2005. Crude oil and condensate production in 2006 averaged 89,401 barrels per day compared to 104,588 barrels per day a year ago. The production decline in 2006 was primarily attributable to lower volumes at the Terra Nova field, which has been shut-in for equipment maintenance since May 2006. Also, U.S. oil volumes were lower during the 2006 period mostly due to lower production in the Gulf of Mexico at the Front Runner and Habanero fields. The average sales price for North American natural gas in the first nine months of 2006 was $7.76 per MCF, up from $7.37 in 2005. Natural gas sales volumes were down from 96 million cubic feet per day in 2005 to 82 million cubic feet per day in 2006, with the decline primarily due to the sale of most mature properties on the continental shelf of the Gulf of Mexico in June 2005 and field decline in the Gulf of Mexico, but partially offset by new production in 2006 from the Seventeen Hands field in the Gulf of Mexico.

Additional details about results of oil and gas operations are presented in the tables on page 25.

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

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


	Three Months Ended September 30,			Nine Months Ended September 30,
	2006		2005	2006	2005
Net crude oil, condensate and gas liquids produced – barrels per day		79,642	94,151	89,401	104,588
United States		20,416	22,352	23,423	29,229
Canada – light		446	532	428	566
– heavy		10,125	10,343	12,893	10,876
– offshore		10,344	20,640	14,048	23,544
– synthetic		12,525	11,782	11,195	10,394
United Kingdom		4,775	6,704	7,112	8,346
Malaysia		11,896	13,683	11,692	13,863
Ecuador		9,115	8,115	8,610	7,770

Net crude oil, condensate and gas liquids sold – barrels per day		73,112	93,910	92,324	105,723
United States		20,416	22,352	23,423	29,229
Canada – light		446	532	428	566
– heavy		10,125	10,343	12,893	10,876
– offshore		9,884	21,359	14,997	23,414
– synthetic		12,525	11,782	11,195	10,394
United Kingdom		2,534	6,967	6,724	8,510
Malaysia		9,939	13,415	12,148	15,071
Ecuador (1)		7,243	7,160	10,516	7,663

Net natural gas sold – thousands of cubic feet per day		73,856	69,544	81,601	96,160
United States		61,072	57,190	63,119	78,947
Canada		8,748	9,351	9,423	10,591
United Kingdom		4,036	3,003	9,059	6,622

Total net hydrocarbons produced – equivalent barrels per day (2)		91,951	105,742	103,001	120,615
Total net hydrocarbons sold – equivalent barrels per day (2)		85,421	105,501	105,924	121,750

Weighted average sales prices
Crude oil and condensate – dollars per barrel (3)
United States	$	61.83	55.38	58.69	46.56
Canada (4) – light		65.86	56.15	60.29	50.75
– heavy (5)		30.62	29.78	26.23	20.47
– offshore		68.60	59.33	64.34	50.45
– synthetic		68.41	63.99	66.15	57.42
United Kingdom		69.62	61.27	66.38	51.66
Malaysia (6)		52.48	47.65	54.10	44.96
Ecuador (7)		31.66	45.99	31.41	35.06
Natural gas – dollars per thousand cubic feet
United States (3)	$	7.12	8.65	7.93	7.46
Canada (4)		5.40	7.87	6.62	6.68
United Kingdom (4)		6.13	4.47	7.39	4.93

(1)	Includes settlement with nonoperator partners of 3,125 barrels per day in the first nine 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 revenue sharing with the Ecuadorian government that was effective in April 2006, and the year-to-date 2006 price was adversely affected by the partial settlement with nonoperator partners of crude oil production owed to the Company since 2004.

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

Continuing

Oil and Gas Operating Results


(Millions of dollars)	United States			Canada		United King- dom		Ecuador	Malaysia		Other		Synthetic Oil – Canada	Total
Three Months Ended September 30, 2006
Oil and gas sales and other revenues	$	157.8		93.7		18.6		21.1	51.2		1.2		78.9	422.5
Production expenses		22.2		33.3		3.8		5.0	6.7		—		26.7	97.7
Depreciation, depletion and amortization		22.4		17.1		2.1		5.4	10.3		.2		4.6	62.1
Accretion of asset retirement obligations		.8		1.0		.5		—	.1		.1		.1	2.6
Net costs associated with hurricanes		.4		—		—		—	—		—		—	.4
Exploration expenses
Dry holes		3.3		—		—		.4	—		(3.0	)	—	.7
Geological and geophysical		2.7		1.0		—		—	22.7		1.2		—	27.6
Other		.6		.2		(.1	)	—	—		1.3		—	2.0

		6.6		1.2		(.1	)	.4	22.7		(.5	)	—	30.3
Undeveloped lease amortization		4.3		1.0		—		—	—		.4		—	5.7

Total exploration expenses		10.9		2.2		(.1	)	.4	22.7		(.1	)	—	36.0

Selling and general expenses		5.5		2.2		.7		.2	3.8		2.4		.2	15.0
Income tax provisions		32.0		4.9		23.6		4.3	8.2		.3		16.6	89.9

Results of operations (excluding corporate overhead and interest)	$	63.6		33.0		(12.0	)	5.8	(.6	)	(1.7	)	30.7	118.8

Three Months Ended September 30, 2005
Oil and gas sales and other revenues	$	168.0		158.4		40.6		30.3	62.4		.8		69.4	529.9
Production expenses		13.9		14.7		4.2		3.7	9.9		—		25.1	71.5
Depreciation, depletion and amortization		19.7		27.9		4.8		5.0	12.8		.1		3.4	73.7
Accretion of asset retirement obligations		.6		.9		.4		—	.1		.2		.1	2.3
Net costs associated with hurricanes*		7.6		2.1		.7		—	.1		—		1.1	11.6
Exploration expenses
Dry holes		(.1	)	—		3.9		—	(.3	)	.4		—	3.9
Geological and geophysical		2.7		2.5		—		—	16.7		.1		—	22.0
Other		.6		.1		—		—	—		.9		—	1.6

		3.2		2.6		3.9		—	16.4		1.4		—	27.5
Undeveloped lease amortization		4.3		.8		—		—	—		.3		—	5.4

Total exploration expenses		7.5		3.4		3.9		—	16.4		1.7		—	32.9

Selling and general expenses		7.4		1.8		.9		.1	1.1		2.6		.2	14.1
Income tax provisions		40.0		36.1		10.5		8.2	11.4		.2		12.8	119.2

Results of operations (excluding corporate overhead and interest)	$	71.3		71.5		15.2		13.3	10.6		(4.0	)	26.7	204.6

Nine Months Ended September 30, 2006
Oil and gas sales and other revenues	$	533.1		375.2		140.5		90.2	172.3		3.3		202.2	1,516.8
Production expenses		59.1		81.5		13.3		22.6	24.1		—		89.0	289.6
Depreciation, depletion and amortization		70.4		71.4		16.6		19.9	35.5		.4		11.9	226.1
Accretion of asset retirement obligations		2.2		3.0		1.4		—	.2		.4		.4	7.6
Net costs associated with hurricanes		1.7		—		—		—	—		—		—	1.7
Exploration expenses
Dry holes		9.4		—		—		1.5	30.6		.4		—	41.9
Geological and geophysical		23.8		.9		—		—	34.8		1.9		—	61.4
Other		4.5		.5		.1		—	.2		4.1		—	9.4

		37.7		1.4		.1		1.5	65.6		6.4		—	112.7
Undeveloped lease amortization		12.8		2.8		—		—	—		1.1		—	16.7

Total exploration expenses		50.5		4.2		.1		1.5	65.6		7.5		—	129.4

Selling and general expenses		15.8		7.5		2.7		.8	7.4		8.5		.6	43.3
Income tax provisions		115.6		43.3		61.7		18.5	35.1		.8		18.7	293.7

Results of operations (excluding corporate overhead and interest)	$	217.8		164.3		44.7		26.9	4.4		(14.3	)	81.6	525.4

Nine Months Ended September 30, 2005
Oil and gas sales and other revenues	$	717.5		414.1		129.4		73.3	185.4		2.6		163.0	1,685.3
Production expenses		64.7		42.8		12.2		14.6	27.1		—		67.7	229.1
Depreciation, depletion and amortization		72.5		91.2		18.3		14.4	39.0		.2		9.4	245.0
Accretion of asset retirement obligations		2.6		2.6		1.2		—	.2		.4		.4	7.4
Net costs associated with hurricanes*		7.6		2.1		.7		—	.1		—		1.1	11.6
Exploration expenses
Dry holes		16.5		(.7	)	3.8		—	21.4		23.0		—	64.0
Geological and geophysical		15.4		4.1		—		—	33.0		1.7		—	54.2
Other		4.1		.4		.3		—	—		2.7		—	7.5

		36.0		3.8		4.1		—	54.4		27.4		—	125.7
Undeveloped lease amortization		14.1		2.3		—		—	—		1.1		—	17.5

Total exploration expenses		50.1		6.1		4.1		—	54.4		28.5		—	143.2

Selling and general expenses		16.8		6.2		2.6		.6	5.1		7.9		.5	39.7
Income tax provisions		182.1		87.5		37.4		17.9	37.0		.7		27.3	389.9

Results of operations (excluding corporate overhead and interest)	$	321.1		175.6		52.9		25.8	22.5		(35.1	)	56.6	619.4

*	Certain additional hurricane-related insurance costs in 2005 were allocated to non-U.S. reporting segments.

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
	Three Months Ended September 30,			Nine Months Ended September 30,
(Millions of dollars)	2006		2005	2006	2005
Refining and marketing
North America	$	114.5	11.2	51.1	62.6
United Kingdom		12.1	20.8	25.0	31.3

Total	$	126.6	32.0	76.1	93.9

The Company’s refining and marketing operations generated a quarterly profit of $126.6 million in the third quarter 2006 compared to a profit of $32.0 million in the 2005 quarter. The earnings improved in 2006 due to higher margins for both refining and marketing operations in North America compared to the 2005 third quarter. Murphy’s downstream business incurred after-tax costs of $16.7 million related to hurricane repairs and the settlement of oil spill class action litigation in the 2006 third quarter, compared to various hurricane-related after-tax costs of $13.9 million in the 2005 period. In the 2005 period, the Meraux refinery experienced flooding associated with Hurricane Katrina and consequently, was shut down for the last 34 days of the quarter. Worldwide petroleum product sales averaged 427,465 barrels per day in 2006, compared to 363,284 barrels per day in the same period in 2005. Worldwide refinery inputs were 170,841 barrels per day in the third quarter of 2006 compared to 145,315 in the 2005 quarter; inputs in 2005 were adversely affected by 34 days of downtime at the Meraux refinery caused by Hurricane Katrina.

The Company’s refining and marketing operations generated a profit of $76.1 million in the first nine months of 2006 compared to a profit of $93.9 million in 2005. The lower 2006 result was based on higher hurricane-related expenses in the United States and lower margins in the U.K. The 2006 and 2005 results included net-of-tax hurricane related costs of $65.1 million and $13.9 million, respectively. The 2005 period was affected by 34 days of hurricane-related downtime at the Meraux refinery. Meraux remained down for repairs for the first five months of 2006.

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2006	2005	2006	2005
Refinery inputs – barrels per day	170,841	145,315	108,968	167,809
North America	136,075	105,454	75,182	135,325
United Kingdom	34,766	39,861	33,786	32,484

Petroleum products sold – barrels per day	427,465	363,284	375,982	358,247
North America	392,374	322,860	341,281	323,790
Gasoline	281,168	243,352	263,601	226,565
Kerosine	284	2,329	2,055	6,269
Diesel and home heating oils	76,239	48,947	56,956	62,697
Residuals	19,318	13,800	10,446	19,023
Asphalt, LPG and other	15,365	14,432	8,223	9,236
United Kingdom	35,091	40,424	34,701	34,457
Gasoline	13,103	14,004	12,341	11,552
Kerosine	4,788	2,506	3,634	2,228
Diesel and home heating oils	11,039	18,227	11,243	15,576
Residuals	4,267	3,545	4,172	3,013
LPG and other	1,894	2,142	3,311	2,088

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

Results of Operations (Contd.)

Corporate and other

The after-tax costs of corporate functions were $22.6 million in the 2006 quarter compared to costs of $14.2 million in the 2005 quarter. The unfavorable costs in 2006 related to more interest expense due to higher average debt balances and higher interest rates and higher administrative expenses, including more employee incentive compensation expense.

Corporate after-tax costs were $50.8 million in the first nine months of 2006 compared to $30.0 million in the 2005 period. The Company had higher net interest expense in the 2006 period due to a combination of higher average debt levels partially offset by higher interest capitalized on development projects. The 2005 period included after-tax foreign exchange charges of $5.6 million, while 2005 included after-tax foreign exchange charges of $2.4 million. Higher administrative expenses in 2006, primarily related to employee incentive compensation costs, also contributed to the higher net corporate costs compared to 2005.

Financial Condition

Net cash provided by continuing operating activities was $614.4 million for the first nine months of 2006 compared to $761.2 million for the same period in 2005. The decline in 2006 was primarily attributable to lower net income and a larger increase in noncash operating working capital in 2006 partially offset by significant pretax gains on disposition of assets in the 2005 period that did not occur in 2006. Changes in operating working capital other than cash and cash equivalents used cash of $306.3 million in the first nine months of 2006 and $150.9 million in the first nine months of 2005. This use of working capital in 2006 was primarily caused by increases in accounts receivable, inventories and prepaid expenses and a decrease in accounts payable that were partially offset by an increase in income taxes payable. Crude oil and finished product inventories increased due to higher product prices and higher volumes held in inventory. Materials and supplies inventory increased due to timing of purchase of supplies for the Company’s Malaysia operations. Prepaid expenses increased due to higher costs relating to insurance premiums and estimated foreign income tax payments by one of the Company’s subsidiaries. Accounts payable and accrued liabilities decreased due to the timing of certain payments and income taxes payable increased due to higher taxes owed on profits in certain taxing jurisdictions. Cash from operating activities was reduced by expenditures for major repairs and asset retirement obligations totaling $13.1 million in 2006 and $30.2 million in 2005, with the decrease from 2005 mostly attributable to a full plant-wide turnaround at the Milford Haven, Wales refinery in the prior year. Proceeds from the sale of assets, excluding discontinued operations, provided cash of $19.8 million in the first nine months of 2006 compared to $173.6 million in the same period in 2005.

Other predominant uses of cash in each period were for dividends, which totaled $70.1 million in 2006 and $62.3 million in 2005 and for capital expenditures, which including amounts expensed, are summarized in the following table.


	Nine Months Ended September 30,
(Millions of dollars)	2006			2005
Capital Expenditures
Exploration and production	$	819.4		765.2
Refining and marketing		131.0		163.3
Corporate and other		4.5		14.3

Total capital expenditures		954.9		942.8
Geological, geophysical and other exploration expenses charged to income		(70.8	)	(61.7	)

Total property additions and dry holes	$	884.1		881.1

Working capital (total current assets less total current liabilities) at September 30, 2006 was $742.1 million, up $190.2 million from December 31, 2005. This level of working capital includes valuing certain inventories using lower historical costs under LIFO accounting. The carrying value of LIFO inventories were $400.8 million below current costs at September 30, 2006.

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

Financial Condition (Contd.)

At September 30, 2006, long-term notes payable of $782.1 million increased $184.2 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 September 30, 2006 and December 31, 2005 follows.


	September 30, 2006			December 31, 2005
(Millions of dollars)	Amount		%	Amount		%
Capital Employed
Notes payable	$	782.1	16.1	$	597.9	14.7
Nonrecourse debt of a subsidiary		7.5	.2		11.6	.3
Stockholders’ equity		4,064.8	83.7		3,461.0	85.0

Total capital employed	$	4,854.4	100.0	$	4,070.5	100.0

As of October 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 19.3 to 1 for the nine months ended September 30, 2006.

Accounting and Other Matters

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

Accounting and Other Matters (Contd.)

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

Accounting and Other Matters (Contd.)

Murphy holds a 20% interest in Block 16 Ecuador, where the Company and its partners produce oil for export. In 2001, the local tax authorities announced that Value Added Taxes (VAT) paid on goods and services related to Block 16 and many oil fields held by other companies will no longer be reimbursed. In response to this announcement, the operator of Block 16 filed numerous actions in the Ecuador Tax Court seeking determination that the VAT in question is reimbursable. In July 2004, international arbitrators ruled that VAT was recoverable by another oil company, but the State of Ecuador responded that it was not bound by this arbitral decision. As of September 30, 2006, the Company has a receivable of approximately $18.9 million related to VAT. Murphy believes that its claim for reimbursement of VAT under applicable Ecuador tax law is valid, and it does not expect that the resolution of this matter will have a material adverse affect on the Company’s net income, financial condition or liquidity in future periods.

Outlook

Crude oil prices have retreated from the levels reached in the third quarter 2006. Natural gas prices in North America are under pressure in the early part of the fourth quarter due to an early fill of winter storage. The Company expects its oil and natural gas production in the fourth quarter of 2006 to average approximately 94,000 barrels of oil equivalent per day compared to about 92,000 barrels of oil equivalent per day in the third quarter of 2006. Sales volumes in the fourth quarter of 2006 are expected to be approximately 93,000 barrels of oil equivalent per day. Total Company production for the full year of 2006 is anticipated to average about 101,000 barrels of oil equivalent per day. The Terra Nova field is scheduled to come back onstream in November after a lengthy period of maintenance downtime. The third coker unit at Syncrude is operating at a gross level of 85,000 barrels per day. At the Company’s Meraux, Louisiana refinery, repairs are essentially completed and the plant is running at slightly less than optimum crude oil throughput rates while start-up issues are being addressed. Further expense associated with repairs at Meraux is dependent on the level of Hurricane Katrina losses experienced by O.I.L., the Company’s primary property insurance provider. O.I.L.’s losses on one event, such as Hurricane Katrina, are limited and this limit has been exceeded. If O.I.L.’s overall losses increase for Hurricane Katrina, the amount of repair costs recovered by the Company will decline. Profit margins on refined products have retreated from levels experienced in the third quarter; therefore, the Company currently anticipates significantly lower refining and marketing profits in the fourth quarter 2006 compared to the third quarter. The Company currently anticipates total capital expenditures of approximately $1.5 billion in 2006.

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 prices of crude oil, natural gas and petroleum products, foreign currency exchange rates and interest 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 September 30, 2006 for a remaining notional volume of 0.2 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 the fourth quarter 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 September 30, 2006, the estimated fair value of these agreements was recorded as an asset of $0.4 million. A 10% increase in the average NYMEX price of natural gas would have increased this asset by $0.1 million, while a 10% decrease would have reduced the asset by a similar amount.

At September 30, 2006, the Company was a party to forward sale contracts covering 4,000 barrels per day in blended heavy oil sales during the fourth quarter 2006. The contracts are intended to hedge the financial exposure of the Company’s blended heavy oil sales in Canada during the contract period and are priced at $25.23 per barrel. At September 30, 2006, the estimated fair value of these agreements was recorded as a $6.1 million liability. A 10% increase in the price of Canadian heavy oil at the Hardisty terminal in Canada would have increased this liability by $1.5 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 15(d)-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 nine-month period ended September 30, 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

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. A trial concerning the 25% disputed interest and any remaining issues was held in the second quarter 2006, and, on September 15, 2006, the Court of Queen’s Bench of Alberta issued a ruling in the Company’s favor. Predator will not appeal. Based on this ruling, approximately $14.8 million of previously disputed natural gas sales proceeds, plus associated interest thereon, is expected to be collected by Murphy by the end of 2006.

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

ITEM 1A. RISK FACTORS

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

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)	The Exhibit Index on page 35 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 July 25, 2006 that included a News Release announcing the Company’s earnings and certain other financial information for the three-month and six-month periods ended June 30, 2006.

(c)	A report on Form 8-K was filed on August 2, 2006 that included a News Release announcing the election of a new director to its Board of Directors and a dividend increase on its common stock. Additionally the Company amended its By-Laws to increase the number of directors from ten to eleven.

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)

November 9, 2006

(Date)

EXHIBIT INDEX


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

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

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

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

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

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

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