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, 2007

¨	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, 2007 was 189,257,665.

MURPHY OIL CORPORATION

TABLE OF CONTENTS


		Page
Part I – Financial Information

Item 1. Financial Statements
Consolidated Balance Sheets		2
Consolidated Statements of Income		3
Consolidated Statements of Comprehensive Income		4
Consolidated Statements of Cash Flows		5
Consolidated Statements of Stockholders’ Equity		6
Notes to Consolidated Financial Statements		7

Item 2. Management’s Discussion and Analysis of Results of Operations and Financial Condition		18

Item 3. Quantitative and Qualitative Disclosures About Market Risk		28

Item 4. Controls and Procedures		28

Part II – Other Information

Item 1. Legal Proceedings		29

Item 1A. Risk Factors		30

Item 6. Exhibits and reports on Form 8-K		30

Signature		31

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)


	(Unaudited) September 30, 2007			December 31, 2006^*
ASSETS
Current assets
Cash and cash equivalents	$	789,665		543,390
Short-term investments in marketable securities		59,821		—
Accounts receivable, less allowance for doubtful accounts of $7,834 in 2007 and $10,408 in 2006		1,079,609		995,089
Inventories, at lower of cost or market
Crude oil and blend stocks		276,101		73,696
Finished products		254,146		224,469
Materials and supplies		132,354		112,912
Prepaid expenses		80,347		136,674
Deferred income taxes		24,544		20,861

Total current assets		2,696,587		2,107,091

Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $3,375,953 in 2007 and $2,872,293 in 2006		6,336,567		5,106,282
Goodwill		51,758		44,057
Deferred charges and other assets		446,032		225,731

Total assets	$	9,530,944		7,483,161


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	5,246		4,466
Notes payable		10,982		2,659
Accounts payable and accrued liabilities		1,424,374		1,240,977
Income taxes payable		79,079		63,003

Total current liabilities		1,519,681		1,311,105

Notes payable		1,493,275		833,126
Nonrecourse debt of a subsidiary		3,159		7,149
Deferred income taxes		779,467		621,329
Asset retirement obligations		293,988		237,875
Deferred credits and other liabilities		533,683		327,964
Minority interest		27,116		23,340

Stockholders’ equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued		—		—
Common Stock, par $1.00, authorized 450,000,000 shares, issued 189,522,070 shares in 2007 and 187,691,508 shares in 2006		189,522		187,692
Capital in excess of par value		532,236		454,860
Retained earnings		3,813,431		3,349,832
Accumulated other comprehensive income		352,278		131,999
Treasury stock, 264,405 shares of Common Stock in 2007 and 119,308 shares in 2006, at cost		(6,892	)	(3,110	)

Total stockholders’ equity		4,880,575		4,121,273


Total liabilities and stockholders’ equity	$	9,530,944		7,483,161

^*	Adjusted to reflect adoption of FASB Staff Position No. AUG AIR-1; See Note B.

See Notes to Consolidated Financial Statements, page 7.

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,
	2007			2006^*		2007		2006*
REVENUES
Sales and other operating revenues	$	4,773,039		4,147,706		12,815,223		10,932,857
Gain (loss) on sale of assets		224		432		1,032		(941	)
Interest and other income		7,469		5,284		12,988		11,687

Total revenues		4,780,732		4,153,422		12,829,243		10,943,603


COSTS AND EXPENSES
Crude oil and product purchases		3,909,009		3,275,816		10,288,096		8,580,267
Operating expenses		320,037		282,251		926,472		790,660
Exploration expenses, including undeveloped lease amortization		42,531		35,970		121,035		129,406
Selling and general expenses		65,591		52,237		173,309		139,160
Depreciation, depletion and amortization		114,289		87,181		337,016		286,745
Impairment of long-lived assets		—		—		40,708		—
Accretion of asset retirement obligations		4,197		2,614		11,461		7,690
Net costs associated with hurricanes		—		27,160		—		105,933
Interest expense		19,837		17,021		52,447		39,262
Interest capitalized		(12,419	)	(11,284	)	(43,664	)	(29,912	)
Minority interest		(448	)	—		(424	)	—

Total costs and expenses		4,462,624		3,768,966		11,906,456		10,049,211


Income before income taxes		318,108		384,456		922,787		894,392
Income tax expense		118,573		160,314		362,376		338,093

NET INCOME	$	199,535		224,142		560,411		556,299


NET INCOME PER COMMON SHARE
BASIC	$	1.06		1.20		2.99		2.99
DILUTED		1.04		1.18		2.94		2.94

Average common shares outstanding – basic		188,239,267		186,211,753		187,716,385		185,948,743
Average common shares outstanding – diluted		191,193,266		189,238,922		190,764,460		189,067,278

^*	Adjusted to reflect adoption of FASB Staff Position No. AUG AIR-1; See Note B.

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,
	2007		2006^*	2007	2006*
Net income	$	199,535	224,142	560,411	556,299

Other comprehensive income, net of tax
Cash flow hedges
Net derivative gains (losses)		—	3,329	—	(5,508	)
Reclassification adjustments		—	6,646	—	15,598

Total cash flow hedges		—	9,975	—	10,090
Net gain from foreign currency translation		102,088	1,985	211,845	73,514
Retirement and postretirement benefit plan adjustments		1,461	—	7,089	13


COMPREHENSIVE INCOME	$	303,084	236,102	779,345	639,916

^*	Adjusted to reflect adoption of FASB Staff Position No. AUG AIR-1; See Note B.

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,
	2007			2006^*
OPERATING ACTIVITIES
Net income	$	560,411		556,299
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		337,016		286,745
Impairment of long-lived assets		40,708		—
Amortization of deferred major repair costs		15,894		13,465
Expenditures for asset retirements		(4,642	)	(3,137	)
Dry hole costs		37,570		41,885
Amortization of undeveloped leases		20,811		16,717
Accretion of asset retirement obligations		11,461		7,690
Deferred and noncurrent income tax charges		31,599		17,226
Pretax losses (gains) from disposition of assets		(1,032	)	941
Net increase in noncash operating working capital		(199,639	)	(306,331	)
Other		64,867		(7,084	)

Net cash provided by operating activities		915,024		624,416


INVESTING ACTIVITIES
Property additions and dry hole costs		(1,279,470	)	(884,144	)
Proceeds from sales of assets		18,751		19,796
Purchases of marketable securities		(59,821	)	—
Expenditures for major repairs		(9,304	)	(10,005	)
Other – net		(9,069	)	(8,417	)

Net cash required by investing activities		(1,338,913	)	(882,770	)


FINANCING ACTIVITIES
Increase in notes payable		668,323		183,989
Decrease in nonrecourse debt of a subsidiary		(4,886	)	(4,667	)
Proceeds from exercise of stock options and employee stock purchase plans		33,837		15,354
Excess tax benefits related to exercise of stock options		21,069		7,057
Cash dividends paid		(91,802	)	(70,056	)
Other		(759	)	—

Net cash provided by financing activities		625,782		131,677


Effect of exchange rate changes on cash and cash equivalents		44,382		10,697


Net increase (decrease) in cash and cash equivalents		246,275		(115,980	)
Cash and cash equivalents at January 1		543,390		585,333


Cash and cash equivalents at September 30	$	789,665		469,353


SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid, net of refunds	$	249,057		372,277

Interest capitalized in excess of interest paid		5,090		3,066

^*	Adjusted to reflect adoption of FASB Staff Position No. AUG AIR-1; See Note B.

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,
	2007			2006
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued		—		—


Common Stock – par $1.00, authorized 450,000,000 shares, issued 189,522,070 shares in 2007 and 187,150,783 shares in 2006
Balance at beginning of period	$	187,692		186,829
Exercise of stock options		1,798		322
Issuance of time-based restricted stock		32		—

Balance at end of period		189,522		187,151


Capital in Excess of Par Value
Balance at beginning of period		454,860		437,963
Exercise of stock options, including income tax benefits		55,038		9,720
Restricted stock transactions and other		3,794		(7,464	)
Amortization, forfeitures and other		17,759		17,169
Sale of stock under employee stock purchase plans		785		409
Reclassification from Unamortized Restricted Stock Awards upon adoption of SFAS No. 123R		—		(16,410	)

Balance at end of period		532,236		441,387


Retained Earnings
Balance at beginning of period as previously reported		—		2,744,274
Cumulative effect of adopting FASB Staff Position No. AUG AIR-1		—		59,051

Balance at beginning of period as adjusted		3,349,832		2,803,325
Cumulative effect of changes in accounting principles		(5,010	)	–
Net income for the period		560,411		556,299
Cash dividends		(91,802	)	(70,056	)

Balance at end of period		3,813,431		3,289,568


Accumulated Other Comprehensive Income
Balance at beginning of period as previously reported		—		131,324
Cumulative effect of adopting FASB Staff Position No. AUG AIR-1		—		2,029

Balance at beginning of period as adjusted		131,999		133,353
Cumulative effect of change in accounting principle		1,345		—
Foreign currency translation gains, net of taxes		211,845		73,514
Cash flow hedging gains, net of taxes		—		10,090
Retirement and postretirement benefit plan adjustments, net of taxes		7,089		13

Balance at end of period		352,278		216,970


Unamortized Restricted Stock Awards
Balance at beginning of period		—		(16,410	)
Reclassification to Capital in Excess of Par upon adoption of SFAS No. 123R		—		16,410

Balance at end of period		—		—


Treasury Stock
Balance at beginning of period		(3,110	)	(22,990	)
Exercise of stock options		—		13,345
Sale of stock under employee stock purchase plans		812		501
Awarded restricted stock, net of forfeitures		—		6,712
Cancellation and forfeitures of performance-based restricted stock		(4,594	)	—

Balance at end of period		(6,892	)	(2,432	)


Total Stockholders’ Equity	$	4,880,575		4,132,644

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, 2006. 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, 2007, and the results of operations, cash flows and changes in stockholders’ equity for the three-month and nine-month periods ended September 30, 2007 and 2006, 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 2006 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, 2007 are not necessarily indicative of future results.

Note B – New Accounting Principles Adopted

Turnaround Accounting

Effective January 1, 2007, the Financial Accounting Standards Board’s (FASB) Staff Position No. AUG AIR-1 (FSP AUG AIR-1), Accounting for Planned Major Maintenance Activities, became effective for the Company. FSP AUG AIR-1 no longer permits the Company to use the accrue-in-advance method of accounting for planned major maintenance activities such as refinery turnarounds. The Company has chosen to use the permitted deferral method for such planned major maintenance activity. All prior period financial statements have been adjusted to reflect the adoption of FSP AUG AIR-1 as if the deferral method was in effect in prior periods. A cumulative after-tax adjustment of $61.1 million has been recorded as of January 1, 2006 as an increase to Stockholders’ Equity to effect the adoption of FSP AUG AIR-1. Net income for the three-month and nine-month periods ended September 30, 2006 has been restated to reflect the earnings for the periods as if FSP AUG AIR-1 had been in effect during the periods. The effect for the three-month and nine-month periods ended September 30, 2006 was an increase to net income of $1.3 million (nil per diluted share) and $5.6 million ($0.03 per diluted share), respectively. As presented on the consolidated balance sheet as of December 31, 2006, the previously reported liability for Accrued Major Repair Costs of $71.2 million has been removed and a noncurrent asset of $37.4 million, representing the unamortized deferred costs of planned major maintenance activities as of that date, has been added to Deferred Charges and Other Assets. In association with the adoption of FSP AUG AIR-1, the Company will present expenditures for major repairs as an investing activity in the Consolidated Statement of Cash Flows. The following consolidated financial statement items as of December 31, 2006 and for the three-month and nine-month periods ended September 30, 2006 were affected by this change in accounting principle.


	December 31, 2006
(Thousands of dollars)	As Previously Reported		FSP AUG AIR-1 Adjustment		As Adjusted
Consolidated Balance Sheet
Deferred charges and other assets	$	188,297	37,434		225,731
Deferred income tax liabilities		581,920	39,409		621,329
Accrued major repair costs		71,229	(71,229	)	—
Deferred credits and other liabilities		327,307	657		327,964
Retained earnings		3,284,391	65,441		3,349,832
Accumulated other comprehensive income		128,843	3,156		131,999
Total stockholders’ equity		4,052,676	68,597		4,121,273

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note B – New Accounting Principles Adopted (Contd.)


	Three-Month Period September 30, 2006					Nine-Month Period September 30, 2006
(Thousands of dollars)	As Previously Reported		FSP AUG AIR-1 Adjustment		As Adjusted	As Previously Reported		FSP AUG AIR-1 Adjustment		As Adjusted
Consolidated Statements of Income
Operating expenses	$	284,375	(2,124	)	282,251	799,369		(8,709	)	790,660
Selling and general expenses		52,251	(14	)	52,237	139,282		(122	)	139,160
Income before income taxes		382,318	2,138		384,456	885,561		8,831		894,392
Income tax expense		159,543	771		160,314	334,839		3,254		338,093
Net income		222,775	1,367		224,142	550,722		5,577		556,299
Net income per share:
Basic		1.20	—		1.20	2.96		.03		2.99
Diluted		1.18	—		1.18	2.91		.03		2.94

Consolidated Statement of Cash Flows
Operating Activities
Net income						550,722		5,577		556,299
Provisions for/amortization of major repair costs						22,296		(8,831	)	13,465
Expenditures for major repairs and asset retirements						(13,142	)	10,005		(3,137	)
Deferred and noncurrent income tax charge						13,972		3,254		17,226
Net cash provided by operating activities						614,411		10,005		624,416

Investing Activities
Expenditures for major repairs						—		(10,005	)	(10,005	)
Net cash required by investing activities						(872,765	)	(10,005	)	(882,770	)

Uncertain Income Tax Positions

Effective January 1, 2007, the Company adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48). This interpretation clarifies the criteria for recognizing income tax benefits under FASB Statement No. 109, Accounting for Income Taxes, and requires additional disclosures about uncertain tax positions. Under FIN 48 the financial statement recognition of the benefit for a tax position is dependent upon the benefit being more likely than not to be sustainable upon audit by the applicable taxing authority. If this threshold is met, the tax benefit is then measured and recognized at the largest amount that is greater than 50 percent likely of being realized upon ultimate settlement. Upon adoption of FIN 48 on January 1, 2007, the Company recognized a $0.7 million increase in its liability for unrecognized income tax benefits, which is included in Deferred Credits and Other Liabilities in the Consolidated Balance Sheet, and it recognized a similar decrease to Retained Earnings. A reconciliation of the beginning and ending amount of the consolidated liability for unrecognized income tax benefits during the nine-month period ended September 30, 2007 is as follows:


(Thousands of dollars)	2007
Balance at January 1, 2007	$	21,998
Additions for tax positions of prior years		1,818
Additions for tax positions related to 2007		2,651
Settlements		(2,129	)
Changes due to translation of foreign currencies		765

Balance at September 30, 2007	$	25,103

All additions or reductions to the above liability affect the Company’s effective income tax rate in the respective period of change. The Company accounts for any applicable interest and penalties on uncertain tax positions as a component of income tax expense. The liability for uncertain income taxes as of the date of adoption (January 1, 2007) and September 30, 2007 includes interest and penalties of $5.5 million and $6.0 million, respectively. Income tax expense for the nine-month period ended September 30, 2007 included a benefit for interest and penalties of $0.3 million associated with uncertain tax positions.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note B – New Accounting Principles Adopted (Contd.)

During the next year, the Company currently expects the liability for uncertain taxes to increase by amounts that are consistent with the increase that occurred during the nine-month period ended September 30, 2007. The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. As of September 30, 2007, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2003; Canada – 2002; United Kingdom – 2005; Malaysia – 2004; and Ecuador – 2000.

Retirement and Postretirement Plans Measurement

In September 2006, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of SFAS Nos. 87, 88, 106 and 132R. 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 all plans as of December 31 rather than September 30 as previously permitted. The Company recognized the funded status position portion of this statement in its Consolidated Balance Sheet as of December 31, 2006. The Company has decided to adopt the requirement to use a December 31 measurement date for defined benefit plan measurement beginning in 2007. The transition from a measurement date as of September 30 to December 31 beginning in 2007 required the Company to reduce its consolidated Retained Earnings as of January 1, 2007 by $4.3 million to recognize the one-time after-tax effect of an additional three months of net periodic benefit expense for its retirement and postretirement benefit plans. The balance sheet adjustments as of January 1, 2007 were as follows:


(Thousands of dollars)	Increase (Decrease)
Deferred income taxes payable	$	(1,708	)
Deferred credits and other liabilities		4,664
Retained earnings		(4,301	)
Accumulated other comprehensive income		1,345

Note C – Property, Plant and Equipment

FASB Staff Position (FSP) 19-1 applies to companies that use the successful efforts method of accounting and it 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.

At September 30, 2007, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $317.0 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2007 and 2006.


(Thousands of dollars)	2007			2006
Beginning balance at January 1	$	315,445		275,256
Additions pending the determination of proved reserves		8,700		155,381
Reclassification to proved properties based on the determination of proved reserves		(7,168	)	(77,683	)
Capitalized costs charged to expense		—		(3,431	)

Ending balance at September 30	$	316,977		349,523

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)	2007		2006
Capitalized exploratory well costs capitalized for one year or less	$	16,235	161,635
Capitalized exploratory well costs capitalized for more than one year		300,742	187,888

Balance at September 30	$	316,977	349,523

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Of the $300.7 million of exploratory well costs capitalized for more than one year, $34.3 million is in the U.S., $198.5 million is in Malaysia, $7.7 million is in Canada and $60.2 million is in the Republic of Congo. The U.S. amount relates to deepwater Gulf of Mexico wells that are 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.

On April 30, 2007, the Company entered into an agreement with Wal-Mart Stores, Inc. to purchase parcels of property leased from Wal-Mart for its Murphy USA retail gasoline stations. The site purchases began in 2007 and will continue into 2008 with expected total capital expenditures of approximately $315 million. In conjunction with this agreement, the Company closed 55 stations in the U.S. and Canada. In the Consolidated Statements of Income for the nine-month period ended September 30, 2007, the Company recorded noncash charges of $40.7 million primarily for impairment of these retail gasoline stations in the U.S. and Canada. The charge includes writedown of remaining undepreciated book value of the station improvements as well as costs of abandonment.

On October 18, 2007, the government of Ecuador enacted into law a levy that increases from 50% to 99% its share of oil sales prices that exceed a threshold reference price level that currently is about $23.25 per barrel. The Company and its partners in Block 16 are considering alternatives, including dispute resolution procedures, for a response to this government action. Under this new price sharing arrangement for Block 16, the Company is evaluating whether its investment is impaired, and if so determined, the Company could have to record an impairment charge to reduce its investment in fixed assets in a future period. The Company’s investment in fixed assets in Ecuador at September 30, 2007 amounted to approximately $109 million.

Note D – 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 frozen 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, 2007 and 2006.


	Three Months Ended September 30,
	2007			2006		2007		2006
(Thousands of dollars)	Pension Benefits					Postretirement Benefits
Service cost	$	2,865		2,519		560		566
Interest cost		6,440		5,314		1,092		1,006
Expected return on plan assets		(5,702	)	(4,959	)	—		—
Amortization of prior service cost		398		380		(67	)	(69	)
Amortization of transitional asset		(164	)	(163	)	—		—
Recognized actuarial loss		1,510		1,606		399		446

Net periodic benefit expense	$	5,347		4,697		1,984		1,949


	Nine Months Ended September 30,
	2007			2006		2007		2006
(Thousands of dollars)	Pension Benefits					Postretirement Benefits
Service cost	$	8,308		7,991		1,634		1,698
Interest cost		18,712		16,332		3,140		3,018
Expected return on plan assets		(16,653	)	(15,411	)	—		—
Amortization of prior service cost		1,094		1,142		(191	)	(207	)
Amortization of transitional asset		(398	)	(481	)	—		—
Recognized actuarial loss		4,350		4,772		1,145		1,338

Net periodic benefit expense	$	15,413		14,345		5,728		5,847

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Murphy expects to contribute $10.8 million to its defined benefit pension plans and $3.8 million to its postretirement benefits plan during 2007. During the nine-month period ended September 30, 2007, the Company made combined contributions of $8.8 million, and remaining funding in the fourth quarter of 2007 for the Company’s domestic and foreign defined benefit pension and postretirement plans is anticipated to be $5.8 million.

Note E – Financing Arrangements

In June 2007, Murphy and certain wholly-owned subsidiaries extended by one year and increased the borrowing capacity of its five year committed credit facility with a major banking consortium. Borrowing capacity under the facility is as follows:


June 2007 through June 2010	$	1.962 billion
June 2010 through June 2011	$	1.905 billion
June 2011 through June 2012	$	1.828 billion

As of September 30, 2007, the Company has borrowed $500.0 million against the available borrowing capacity.

Note F – Incentive Plans

SFAS No. 123R, Share Based Payment, 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. 123R on January 1, 2006. Prior to 2006, the Company used APB No. 25 to account for stock-based compensation.

At the annual meeting of shareholders on May 9, 2007, two new incentive compensation plans were approved and the Employee Stock Purchase Plan was amended. The 2007 Annual Incentive Plan (2007 Annual Plan) authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and other key employees. Cash awards under the 2007 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee. The 2007 Long-Term Incentive Plan (2007 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units, performance units, performance shares, dividend equivalents and other stock-based incentives. The 2007 Long-Term Plan expires in 2017. A total of 6,700,000 shares are issuable during the life of the 2007 Long-Term Plan, with annual grants limited to 1% of Common shares outstanding. The Employee Stock Purchase Plan was amended to increase the number of shares authorized to be issued under the plan from 600,000 to 980,000, and to extend the term of the plan through June 30, 2017.

The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock and stock options or a combination thereof to the Company’s Directors.

Upon approval by shareholders, the 2007 Long-Term Plan replaced the 1992 Stock Incentive Plan (1992 Plan). The 1992 Plan authorized 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), SAR, and/or restricted stock. Annual grants could not exceed 1% of shares outstanding at the end of the preceding year; allowed shares not granted may be granted in future years.

Cash received from options exercised under all share-based payment arrangements for the nine-month periods ended September 30, 2007 and 2006 was $33.8 million and $15.4 million, respectively. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $24.1 million and $5.7 million for the nine-month periods ended September 30, 2007 and 2006, respectively.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note F – Incentive Plans (Contd.)

In February 2007, the Committee granted 895,500 shares of stock options at an exercise price of $51.07 per share. The Black-Scholes valuation for these awards was $15.02 per share. The Committee also issued 299,000 shares of performance-based restricted stock units in February 2007 under the 2007 Long-Term Plan approved by shareholders on May 9, 2007. For accounting purposes the units were considered granted and outstanding on the date the 2007 Plan was approved by shareholders. The fair value of these performance-based restricted stock units, using a Monte Carlo valuation model, was $47.10 per share. Also in February the Committee granted 32,750 shares of time-lapse restricted stock to the Company’s Directors under the 2003 Director Plan. These shares 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 $50.95 per share.

Note G – 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, 2007 and 2006. 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)	2007	2006	2007	2006
Basic method	188,239,267	186,211,753	187,716,385	185,948,743
Dilutive stock options	2,953,999	3,027,169	3,048,075	3,118,535

Diluted method	191,193,266	189,238,922	190,764,460	189,067,278

Certain options to purchase shares of common stock were outstanding during the 2007 and 2006 periods but were not included in the computation of diluted EPS because the incremental shares from assumed conversion were antidilutive. These included options for 1,545,650 shares at a weighted average share price of $53.70 in each 2007 period and 787,500 shares at a weighted average share price of $57.32 in each 2006 period.

Note H – Financial Instruments and Risk Management

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

•

Crude Oil Purchase Price Risks – The Company purchases crude oil as feedstock at its U.S. and U.K. refineries and is therefore subject to commodity price risk. Short-term derivative instruments were outstanding at September 30, 2007 to manage the purchase price of about 1.7 million barrels of crude oil at the Company’s Meraux, Louisiana refinery. The total impact of marking these contracts to market was a charge of $7.1 million in the nine-month period ended September 30, 2007.

•

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 hedged the cash flow risk associated with the cost of a portion of the natural gas it purchased at Meraux in 2006 by entering into financial contracts known as natural gas swaps covering notional volumes of 2,000 MMBTU (million British Thermal Units) per day in 2006. Under the natural gas swaps, the Company paid a fixed rate averaging $3.35 per MMBTU and received a floating rate in each month of settlement based on the average NYMEX price for the final three trading days of the month. The fair value of the effective portions of the natural gas swaps and changes thereto is deferred in AOCI and is subsequently reclassified into Crude Oil and Product Purchases in the income statements in the periods in which the hedged natural gas fuel purchases affect earnings. During the nine-month period ended September 30, 2006, the Company received approximately $2.2 million for maturing swap agreements. For the nine-month period ended September 30, 2006, the income effect from cash flow hedging ineffectiveness for these contracts was insignificant. There were no forecasted natural gas purchases hedged during 2007.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

•

Crude Oil Sales Price Risks – The sales price of crude oil produced by the Company is subject to commodity price risk. Murphy 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 paid the average of the posted price for blended heavy oil at the Hardisty terminal in Canada for each month and received at that location a fixed price of $25.23 per barrel in 2006. The fair values of the effective portions of the crude oil hedges and changes thereto are deferred in AOCI and are subsequently reclassified into Sales and Other Operating Revenues in the income statement in the periods in which the hedged crude oil sales affect earnings. During the nine-month period ended September 30, 2006, the Company paid approximately $23.9 million for settlement of maturing forward sale contracts. During the nine-month period ended September 30, 2006, cash flow hedging ineffectiveness relating to the crude oil sales contracts was insignificant. The fair value of the crude oil sales contracts are based on the average fixed price of the instruments and the published NYMEX index futures price or crude oil price quotes from counterparties. There were no forecasted sales of crude oil hedged during 2007.

Note I – Accumulated Other Comprehensive Income

The components of Accumulated Other Comprehensive Income on the Consolidated Balance Sheets at September 30, 2007 and December 31, 2006 are presented in the following table.


(Thousands of dollars)	September 30, 2007			December 31, 2006
Foreign currency translation gains, net of tax	$	436,000		224,894
Retirement and postretirement benefit plan adjustments, net of tax		(83,722	)	(92,895	)

Accumulated other comprehensive income	$	352,278		131,999

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 was not significant.

Note J – Hurricane Related Matters

In the nine-month period ended September 30, 2006, the Company recorded pretax expenses, net of anticipated insurance recoveries, of $105.9 million, associated with hurricanes that occurred in the United States in 2005, including $104.2 million at the Meraux refinery. The components of these refinery costs 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 for the temporarily idled refinery. The costs are reported in Net Costs Associated With Hurricanes in the Consolidated Statement of Income. See Note K for additional information regarding environmental and other contingencies related to Hurricane Katrina. Total amounts receivable from insurers for hurricane-related matters was $86.8 million at September 30, 2007, including $38.1 million related to oil spill payments and $48.7 million related to property damage incurred as a result of Hurricane Katrina. Approximately $63.0 million of the amounts receivable from insurers was not anticipated to be collected in the next twelve months, and has therefore been classified as a noncurrent asset.

The Company maintains insurance coverage related to losses of production and profits for occurrences such as storms, fires and other issues. During the nine-month periods ended September 30, 2007 and 2006, the Company received insurance proceeds of $2.0 million and $15.7 million, respectively, related to loss of production in the Gulf of Mexico associated with hurricanes in prior years. These amounts are reported in Sales and Other Operating Revenues in the Consolidated Statements of Income.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – 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; royalty increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Because governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences, and may be taken in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.

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 70 service stations for which known or potential obligations for environmental remediation exist. In addition the Company operates or has operated numerous oil and gas fields that may require some form of remediation, which is generally provided for by the Company’s asset retirement obligation.

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

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – Environmental and Other Contingencies (Contd.)

paid by the Company and are expected to total $55 million. Approximately 75 non-class action suits regarding the oil spill have been filed and remain pending. The Company believes that insurance coverage exists and it does not expect to incur significant costs associated with this litigation. On August 14, 2007, four of the Company’s high level excess insurers noticed the Company for arbitration in London. The insurers do not deny coverage, but seek arbitration as to whether and to what extent expenditures made by the Company in resolving the oil spill litigation have reached the attachment point for covered loss under their respective policies. The Company is of the position that full coverage should be afforded. Accordingly, the Company believes neither the ultimate resolution of the remaining litigation nor the insurance arbitration will 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 where a class certification hearing is scheduled for November 20, 2007. 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.

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, 2007, the Company had contingent liabilities of $10.7 million under a financial guarantee and $141.9 million on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to these letters of credit because it is believed that the likelihood of having these drawn is remote.

Note L – Accounting Matters

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS No. 159). This pronouncement permits companies with eligible financial assets and financial liabilities to measure these items at fair value in the financial statements. This option to measure at fair value is both instrument specific and irrevocable. If the fair value option is elected, certain additional disclosures are required. This pronouncement is effective in fiscal years beginning after November 15, 2007, but early adoption at the beginning of an earlier fiscal year is permitted as long as adoption occurs before any interim financial statements have been issued for the earlier fiscal year. If the fair value option is elected, financial statements for periods prior to the adoption may not be restated. The Company is considering SFAS No. 159, and the Company is unable to predict at this time whether the fair value option will be elected, and if so, how this decision would effect its consolidated financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note L – Accounting Matters (Contd.)

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 June 2007, the FASB ratified the Emerging Issues Task Force’s Issue No. 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards. This new guidance will be effective for the Company beginning in 2008, and will require that income tax benefits received by the Company for dividends paid on share-based incentive awards be recorded in Capital in Excess of Par Value in Stockholders’ Equity. Under certain circumstances, such tax benefits received on awards that do not vest could be reclassified to reduce income tax expense in the Consolidated Statements of Income. The Company does not expect the adoption of this consensus to have a material impact on its financial statements.

Note M – Commitments

In 2007, the Company entered into contracts for drilling rigs and associated equipment for periods beyond September 30, 2007. The rigs are to be utilized for drilling operations in Malaysia, the United States and the Republic of Congo. The commitments, which expire in 2010 through 2012, total approximately $1,021 million. A portion of these costs will be borne by other working interest owners when the wells are drilled. These drilling costs are expected to be accounted for as capital expenditures as incurred during the contract periods.

The Company leases land, gasoline stations and other facilities under operating leases. During 2007, the Company entered into an eight-year operating lease for certain equipment used at the Kikeh field offshore Sabah, Malaysia. The Company’s annual rental costs over the term of this lease are approximately $65.3 million.

Note N – Income Taxes

The nine-month period of 2007 includes income tax benefits of $3.8 million related to enacted Canadian Federal and United Kingdom tax rate reductions and the three-month and nine-month periods in 2007 include a benefit of $8.3 million for settlements and other adjustments in Canada related to prior years’ tax matters. Income tax expense for the three-month and nine-month periods in 2006 included 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 included a tax-benefit of $37.5 million related to Canadian Federal and provincial tax rate reductions enacted by these governments in the second quarter 2006.

Note O – Pending Acquisition

In August 2007, a wholly-owned subsidiary of the Company agreed terms to purchase Total’s 70% of the Milford Haven Wales, U.K., refinery for $250 million. Additionally, a purchase and sale agreement was signed on October 3. Prior to the completion of this transaction, the Company owns an effective 30% interest in the 108,000 barrel per day refinery located in Pembrokeshire in Southwest Wales. The purchase is expected to be completed in the fourth quarter of 2007 and includes the land, refinery complex, jetty and pipeline connection to the Mainline Pipeline.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note P – Business Segments


			Three Months Ended September 30, 2007				Three Months Ended September 30, 2006¹
(Millions of dollars)	Total Assets at Sept. 30, 2007		External Revenues	Inter- segment Revenues	Income (Loss)		External Revenues	Inter- segment Revenues	Income (Loss)
Exploration and production²
United States	$	1,023.0	101.4	—	24.8		157.8	—	63.6
Canada		2,139.7	237.9	45.9	107.1		129.2	43.4	63.6
United Kingdom		202.0	38.3	—	11.0		18.6	—	(12.0	)
Malaysia		1,964.0	33.4	—	4.3		51.2	—	(.6	)
Ecuador		139.2	36.3	—	10.3		21.1	—	5.8
Other		352.2	1.0	—	(6.7	)	1.2	—	(1.7	)

Total		5,820.1	448.3	45.9	150.8		379.1	43.4	118.7

Refining and marketing
North America		2,346.7	3,992.9	—	63.9		3,490.1	—	115.6
United Kingdom		403.3	332.0	—	9.3		278.9	—	12.4

Total		2,750.0	4,324.9	—	73.2		3,769.0	—	128.0

Total operating segments		8,570.1	4,773.2	45.9	224.0		4,148.1	43.4	246.7
Corporate		960.8	7.5	—	(24.5	)	5.3	—	(22.6	)

Total	$	9,530.9	4,780.7	45.9	199.5		4,153.4	43.4	224.1


	Nine Months Ended September 30, 2007					Nine Months Ended September 30, 2006¹
(Millions of dollars)	External Revenues		Inter- segment Revenues	Income (Loss)		External Revenues	Inter- segment Revenues	Income (Loss)
Exploration and production²
United States	$	300.0	—	59.3		533.1	—	217.8
Canada		635.4	91.0	263.6		486.7	90.7	246.2
United Kingdom		121.1	—	37.9		140.5	—	44.7
Malaysia		126.3	—	29.2		172.3	—	4.4
Ecuador		98.8	—	24.3		90.2	—	26.9
Other		2.9	—	(25.4	)	3.3	—	(14.3	)

Total		1,284.5	91.0	388.9		1,426.1	90.7	525.7

Refining and marketing
North America		10,685.1	—	205.6		8,724.4	—	55.3
United Kingdom		846.6	—	27.5		781.7	—	26.0

Total		11,531.7	—	233.1		9,506.1	—	81.3

Total operating segments		12,816.2	91.0	622.0		10,932.2	90.7	607.0
Corporate		13.0	—	(61.6	)	11.4	—	(50.7	)

Total	$	12,829.2	91.0	560.4		10,943.6	90.7	556.3

¹	Results for 2006 have been adjusted to reflect the adoption of FSP AUG AIR-1, Accounting for Planned Major Maintenance Activities.

²	Additional details about results of oil and gas operations are presented in the tables on pages 23 and 24.

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 2007 was $199.5 million, $1.04 per diluted share, compared to net income of $224.1 million, $1.18 per diluted share, in the third quarter of 2006. Higher quarterly profit for the Company’s exploration and production operations in the just completed 2007 quarter was more than offset by lower earnings in refining and marketing operations and higher after-tax corporate costs. The 2006 third quarter included income tax charges and costs associated with hurricanes that occurred in the U.S. during 2005.

For the nine months of 2007, net income totaled $560.4 million, $2.94 per diluted share, compared to $556.3 million, $2.94 per diluted share, for the 2006 period. Murphy’s results of operations by line of business are presented below.


	Income (Loss)
	Three Months Ended September 30,					Nine Months Ended September 30,
(Millions of dollars)	2007			2006		2007		2006
Exploration and production	$	150.8		118.7		388.9		525.7
Refining and marketing		73.2		128.0		233.1		81.3
Corporate		(24.5	)	(22.6	)	(61.6	)	(50.7	)

Net income	$	199.5		224.1		560.4		556.3

The Company’s income contribution from exploration and production (E&P) operations was $150.8 million in the third quarter of 2007 compared to $118.7 million in the same quarter of 2006. The improved earnings in 2007 were mostly attributable to higher oil sales prices, higher oil sales volumes primarily due to higher production at Terra Nova and Syncrude in 2007, and an income tax charge of $17.8 million in the third quarter 2006 related to a 10% tax rate increase in the U.K. The Company’s refining and marketing operations generated a quarterly profit of $73.2 million in the 2007 quarter compared to a profit of $128.0 million in the 2006 quarter, with the reduced earnings primarily due to lower margins for refining and marketing operations in North America, partially offset by hurricane-related costs that occurred in 2006 in the U.S. The after-tax costs of the corporate functions were $24.5 million in the 2007 quarter compared to costs of $22.6 million in the 2006 quarter and the higher net costs were due to a combination of higher net interest and administrative expenses.

The Company’s exploration and production operations earned $388.9 million in the first nine months of 2007 and $525.7 million in the same period of 2006. The primary reason for the reduced earnings in this business in 2007 was lower crude oil sales volumes in the 2007 period, mostly attributable to lower oil produced in the U.S. Gulf of Mexico and the West Patricia field, offshore Malaysia, but these were partially offset by higher production at the Terra Nova field, which was shut down for equipment maintenance for several months during the 2006 period, and higher crude oil sales prices realized in 2007 compared to 2006. Exploration expenses were $121.0 million in 2007 compared to $129.4 million in 2006 as the current period included lower costs for unsuccessful drilling and geophysical activities. The Company’s refining and marketing operations generated a profit of $233.1 million in the first nine months of 2007 compared to a profit of $81.3 million in 2006. The higher 2007 refining and marketing profit was mostly based on strong North American refining margins, higher crude oil throughputs at the Meraux refinery, and lower hurricane-related expenses in the U.S. Corporate after-tax costs were $61.6 million in the first nine months of 2007 compared to $50.7 million in the 2006 period. The Company had higher net interest expense and higher administrative expenses in 2007 compared to 2006.

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

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production

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


	Income (Loss)
	Three Months Ended September 30,					Nine Months Ended September 30,
(Millions of dollars)	2007			2006		2007		2006
Exploration and production
United States	$	24.8		63.6		59.3		217.8
Canada		107.1		63.6		263.6		246.2
United Kingdom		11.0		(12.0	)	37.9		44.7
Malaysia		4.3		(.6	)	29.2		4.4
Ecuador		10.3		5.8		24.3		26.9
Other		(6.7	)	(1.7	)	(25.4	)	(14.3	)

Total	$	150.8		118.7		388.9		525.7

Third quarter 2007 vs. 2006

Exploration and production operations in the U.S. reported earnings of $24.8 million in the third quarter of 2007 compared to earnings of $63.6 million in the same period a year ago. The decline in earnings in 2007 was primarily caused by lower oil and natural gas sales volumes. Exploration expenses increased in the 2007 period compared to 2006 primarily due to higher geophysical costs incurred in the Gulf of Mexico. Selling and general costs were higher in 2007 compared to 2006 mostly caused by a donation of real estate during the just completed quarter. Oil sales prices in 2007 were higher than in 2006, but natural gas sales prices were lower in the 2007 period.

Operations in Canada earned $107.1 million in the third quarter 2007 compared to $63.6 million a year ago. This increase was mainly the result of higher crude oil sales volumes and higher oil sales prices. Production increased mostly at the Terra Nova field, offshore Newfoundland, which was shut-in for equipment maintenance during the entire third quarter of 2006. Unfavorable variances in 2007 included higher expenses for production and depreciation due to more sales volumes in the current period, and exploration expenses were up due to higher dry holes, geological and geophysical and lease amortization costs. Both periods benefited from income tax benefits related to adjustments of estimated prior-period taxes, and these totaled $8.3 million in 2007 and $7.6 million in 2006.

U.K. operations reported earnings of $11.0 million in the 2007 quarter compared to a loss of $12.0 million in the 2006 quarter. The improvement in 2007 was primarily due to a $17.8 million income tax charge in the 2006 third quarter associated with a 10% tax rate increase on U.K. oil and gas profits that was retroactive to the beginning of 2006. The 2007 third quarter benefited from higher crude oil sales prices and sales volumes compared to 2006, but higher oil sales volumes also led to higher production and depreciation expenses. Although sales volumes increased in the 2007 third quarter, oil production in the U.K. was lower primarily due to field decline at Mungo/Monan and planned downtime for repairs at the Schiehallion field in the just completed period.

Operations in Malaysia reported a profit of $4.3 million in the 2007 quarter compared to a loss of $0.6 million during the same period in 2006. The improved results in Malaysia in 2007 were primarily due to lower geophysical expenses and higher oil sales prices in the just completed period. This was partially offset by lower oil production and sales volume at the West Patricia field, offshore Sarawak. Total crude oil production in Malaysia was higher in 2007 than 2006 due to start-up of the Kikeh field, offshore Sabah, and this field added 9,553 barrels of oil per day during the quarter. There were no sales of Kikeh crude oil, and therefore no revenue recorded, in the third quarter. The first sale of Kikeh oil occurred in October.

Operations in Ecuador earned $10.3 million in the third quarter of 2007 compared to earnings of $5.8 million a year ago. The improvement was due to a combination of higher oil sales volumes and higher oil sales prices. Production and depreciation expenses were higher in 2007 in association with the increased oil sales volumes.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

Other international operations reported a loss of $6.7 million in the third quarter of 2007 compared to a loss of $1.7 million in the comparable quarter a year ago. Higher selling and general expenses and higher exploration expenses in the Republic of Congo were the primary reasons for the higher net costs in the current period.

On a worldwide basis, the Company’s crude oil and condensate prices averaged $63.96 per barrel in the 2007 third quarter compared to $55.50 in the third quarter of 2006. Average crude oil and liquids production was 87,962 barrels per day in the third quarter of 2007 compared to 79,642 barrels per day in the third quarter of 2006. The production increase in 2007 was primarily attributable to start-up of the Kikeh field in mid-August and higher production at the Terra Nova field, offshore Newfoundland, which was shut-in for equipment maintenance during the entire 2006 period. Oil production in the U.S. declined in the 2007 period primarily due to lower volumes produced at the Medusa and Front Runner fields in the Gulf of Mexico. Production of synthetic oil in Canada increased in 2007 due mostly to start-up of a third coker unit on August 31, 2006, but partially offset by a higher royalty rate in the current year. Crude oil sales volumes averaged 78,702 barrels per day in the third quarter 2007 compared to 73,112 barrels per day in the 2006 period. North American natural gas sales prices averaged $6.22 per thousand cubic feet (MCF) in the most recent quarter compared to $6.90 per MCF in the same quarter of 2006. Natural gas sales volumes averaged 56 million cubic feet per day in the third quarter 2007, down from 74 million cubic feet per day in the 2006 quarter. The reduction in natural gas sales volumes was primarily due to decline at several fields in the Gulf of Mexico and onshore South Louisiana.

Nine months 2007 vs. 2006

In the first nine months of 2007, operations in the United States produced income of $59.3 million compared to income of $217.8 million in the 2006 period. The decline in 2007 earnings was primarily due to lower oil and natural gas sales volumes, and higher dry hole and selling and general expenses, the latter of which was mostly attributable to a real estate donation.

Canadian operations earned $263.6 million in the nine months ended September 30, 2007 compared to $246.2 million in the same period in 2006. The 2007 period had improved earnings compared to 2006 due to higher crude oil sales volumes and higher oil sales prices. Oil sales were favorable mostly due to higher oil volumes produced at the Terra Nova field offshore Newfoundland. This field was off production for maintenance operations for approximately five months in 2006. The 2007 and 2006 periods included $4.8 million and $37.5 million, respectively, of income tax benefits related to enacted Federal and provincial tax rate reductions, and the 2007 and 2006 periods included additional benefits of $8.3 million and $7.6 million, respectively, relating to adjustments of estimated prior-period Canadian taxes. Exploration expenses were higher in 2007 than 2006 due to more costs for dry holes and geophysical activities. Depreciation expense increased in 2007 compared to 2006 due to higher sales volumes and higher per-unit costs. Selling and general expenses were higher in 2007 compared to 2006 primarily due to administrative costs at Berkana Energy, 80% of which was acquired by the Company in December 2006.

Income in the U.K. for the nine-month period ended September 30, 2007 was $37.9 million compared to $44.7 million a year ago. The decrease was primarily due to lower crude oil and natural gas sales volumes and higher expenses for production and depreciation, partially offset by income tax charges of $17.8 million in 2006 associated with a 10% tax rate increase on U.K. oil and natural gas profits.

Malaysia operations earned $29.2 million in the 2007 nine-month period compared to $4.4 million a year ago. The increase in 2007 earnings was primarily due to lower exploration expenses, but this was partially offset by lower crude oil sales volumes. Production increased slightly in 2007 compared to the prior period as volumes from the new Kikeh field that came on stream in mid-August more than offset decline at the maturing West Patricia field.

For the first nine months of 2007, earnings in Ecuador were $24.3 million compared to $26.9 million for the 2006 period. Lower earnings in 2007 were mostly caused by lower crude oil sales volumes and higher production and depreciation expenses. Higher oil sales volumes in 2006 were partly attributable to a settlement with nonoperator partners of crude oil production owed to the Company from 2004.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

Other international operations reported a loss of $25.4 million in the first nine months of 2007 compared to a loss of $14.3 million in the 2006 period. Higher losses were mostly due to higher geophysical and administrative costs in 2007 compared to 2006.

For the nine-month period ended September 30, 2007, the Company’s sales price for crude oil and condensate averaged $56.10 per barrel compared to $52.80 per barrel in the same period of 2006. Crude oil and condensate production in 2007 averaged 84,169 barrels per day compared to 89,401 barrels per day a year ago. The production decline in 2007 was primarily attributable to lower volumes at offshore fields in the Gulf of Mexico and United Kingdom, partially offset by higher volumes at the Terra Nova field, which was shut-in for equipment maintenance for approximately five months during the 2006 period. The average sales price for North American natural gas in the first nine months of 2007 was $7.16 per MCF, down from $7.76 in 2006. Natural gas sales volumes were down from 82 million cubic feet per day in 2006 to 58 million cubic feet per day in 2007, with the reduction primarily due to field declines in the Gulf of Mexico and onshore South Louisiana.

Additional details about results of oil and gas operations are presented in the tables on pages 23 and 24.

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, 2007 and 2006 follow.


	Three Months Ended September 30,			Nine Months Ended September 30,
	2007		2006	2007	2006
Net crude oil, condensate and gas liquids produced – barrels per day		87,962	79,642	84,169	89,401
United States		11,680	20,416	13,069	23,423
Canada – light		640	446	587	428
– heavy		11,144	10,125	11,197	12,893
– offshore		20,248	10,344	19,862	14,048
– synthetic		14,423	12,525	12,865	11,195
United Kingdom		3,575	4,775	5,108	7,112
Malaysia		17,358	11,896	12,473	11,692
Ecuador		8,894	9,115	9,008	8,610

Net crude oil, condensate and gas liquids sold – barrels per day		78,702	73,112	82,245	92,324
United States		11,680	20,416	13,069	23,423
Canada – light		640	446	587	428
– heavy		11,144	10,125	11,197	12,893
– offshore		20,153	9,884	20,151	14,997
– synthetic		14,423	12,525	12,865	11,195
United Kingdom		5,123	2,534	6,152	6,724
Malaysia		6,359	9,939	8,706	12,148
Ecuador (1)		9,180	7,243	9,518	10,516

Net natural gas sold – thousands of cubic feet per day		55,712	73,856	57,784	81,601
United States		41,667	61,072	42,283	63,119
Canada		10,582	8,748	9,569	9,423
United Kingdom		3,463	4,036	5,932	9,059

Total net hydrocarbons produced – equivalent barrels per day (2)		97,247	91,951	93,800	103,001
Total net hydrocarbons sold – equivalent barrels per day (2)		87,987	85,421	91,876	105,924

Weighted average sales prices
Crude oil and condensate – dollars per barrel (3)
United States	$	70.50	61.83	59.55	58.69
Canada (4) – light		56.77	65.86	50.73	60.29
– heavy (5)		34.91	30.62	32.43	26.23
– offshore		73.97	68.60	65.66	64.34
– synthetic		77.78	68.41	69.15	66.15
United Kingdom		75.88	69.62	65.68	66.38
Malaysia (6)		61.01	52.48	53.33	54.10
Ecuador (7)		43.07	31.66	38.00	31.41
Natural gas – dollars per thousand cubic feet
United States (3)	$	6.59	7.12	7.37	7.93
Canada (4)		4.74	5.40	6.21	6.62
United Kingdom (4)		7.17	6.13	6.84	7.39

(1)	Includes settlement with nonoperator partners of 3,125 barrels per day in the nine months ended September 30, 2006 for Block 16 crude oil withheld from the Company in 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 in 2006.

(6)	Prices are net of payments under the terms of the production sharing contract for Block SK 309.

(7)	All prices are net of revenue sharing with the Ecuadorian government that was legislated effective in April 2006, and the year-to-date 2006 price was adversely affected by the settlement with nonoperator partners of crude oil production withheld from the Company in 2004.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Oil and Gas Operating Results – Three Months Ended September 30, 2007 and 2006


(Millions of dollars)	United States		Canada		United Kingdom		Malaysia		Ecuador	Other		Synthetic Oil – Canada	Total
Three Months Ended September 30, 2007
Oil and gas sales and other revenues	$	101.4	180.5		38.3		33.4		36.3	1.0		103.3	494.2
Production expenses		16.2	29.3		9.0		9.9		8.8	—		35.6	108.8
Depreciation, depletion and amortization		17.6	41.0		5.2		5.2		10.0	.2		7.3	86.5
Accretion of asset retirement obligations		1.1	1.3		.5		.9		—	.2		.2	4.2
Exploration expenses
Dry holes		4.5	6.9		—		(2.2	)	—	—		—	9.2
Geological and geophysical		9.5	4.2		—		9.0		—	.7		—	23.4
Other		.5	.1		.1		—		—	1.3		—	2.0

		14.5	11.2		.1		6.8		—	2.0		—	34.6
Undeveloped lease amortization		4.5	3.1		—		—		—	.3		—	7.9

Total exploration expenses		19.0	14.3		.1		6.8		—	2.3		—	42.5

Selling and general expenses		13.0	4.0		.9		1.6		.2	4.8		.2	24.7
Minority interest		—	(.4	)	—		—		—	—		—	(.4	)

Results of operations before taxes		34.5	91.0		22.6		9.0		17.3	(6.5	)	60.0	227.9
Income tax expenses		9.7	23.9		11.6		4.7		7.0	.2		20.0	77.1

Results of operations (excluding corporate overhead and interest)	$	24.8	67.1		11.0		4.3		10.3	(6.7	)	40.0	150.8


Three Months Ended September 30, 2006
Oil and gas sales and other revenues	$	157.8	93.7		18.6		51.2		21.1	1.2		78.9	422.5
Production expenses		22.2	33.3		3.8		6.7		5.0	—		26.8	97.8
Depreciation, depletion and amortization		22.4	17.1		2.1		10.3		5.4	.2		4.6	62.1
Accretion of asset retirement obligations		.8	1.0		.5		.1		—	.1		.1	2.6
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	)	22.7		.4	(.5	)	—	30.3
Undeveloped lease amortization		4.3	1.0		—		—		—	.4		—	5.7

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

Net costs associated with hurricanes		.4	—		—		—		—	—		—	.4
Selling and general expenses		5.5	2.2		.7		3.8		.2	2.4		.2	15.0

Results of operations before taxes		95.6	37.9		11.6		7.6		10.1	(1.4	)	47.2	208.6
Income tax expenses		32.0	4.9		23.6		8.2		4.3	.3		16.6	89.9

Results of operations (excluding corporate overhead and interest)	$	63.6	33.0		(12.0	)	(.6	)	5.8	(1.7	)	30.6	118.7

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Oil and Gas Operating Results – Nine Months Ended September 30, 2007 and 2006


(Millions of dollars)	United States		Canada		United Kingdom	Malaysia		Ecuador	Other		Synthetic Oil – Canada	Total
Nine Months Ended September 30, 2007
Oil and gas sales and other revenues	$	300.0	483.5		121.1	126.3		98.8	2.9		242.9	1,375.5
Production expenses		59.6	76.1		22.2	27.1		27.6	—		96.1	308.7
Depreciation, depletion and amortization		51.0	116.4		17.6	21.0		28.7	.5		19.1	254.3
Accretion of asset retirement obligations		2.9	3.5		1.5	2.5		—	.5		.5	11.4
Exploration expenses
Dry holes		32.0	7.8		—	(2.1	)	.3	(.4	)	—	37.6
Geological and geophysical		20.9	8.5		—	14.1		—	9.8		—	53.3
Other		4.3	.3		.3	—		—	4.4		—	9.3

		57.2	16.6		.3	12.0		.3	13.8		—	100.2
Undeveloped lease amortization		13.4	6.3		—	–		—	1.1		—	20.8

Total exploration expenses		70.6	22.9		.3	12.0		.3	14.9		—	121.0

Impairment of long-lived assets		2.6	—		—	—		—	—		—	2.6
Selling and general expenses		25.3	12.5		2.8	8.4		.7	11.7		.6	62.0
Minority interest		—	(.4	)	—	—		—	—		—	(.4	)

Results of operations before taxes		88.0	252.5		76.7	55.3		41.5	(24.7	)	126.6	615.9
Income tax expenses		28.7	75.8		38.8	26.1		17.2	.7		39.7	227.0

Results of operations (excluding corporate overhead and interest)	$	59.3	176.7		37.9	29.2		24.3	(25.4	)	86.9	388.9


Nine Months Ended September 30, 2006
Oil and gas sales and other revenues	$	533.1	375.2		140.5	172.3		90.2	3.3		202.2	1,516.8
Production expenses		59.1	81.5		13.3	24.1		22.6	—		88.5	289.1
Depreciation, depletion and amortization		70.4	71.4		16.6	35.5		19.9	.4		11.9	226.1
Accretion of asset retirement obligations		2.2	3.0		1.4	.2		—	.4		.4	7.6
Exploration expenses
Dry holes		9.4	—		—	30.6		1.5	.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	65.6		1.5	6.4		—	112.7
Undeveloped lease amortization		12.8	2.8		—	—		—	1.1		—	16.7

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

Net costs associated with hurricanes		1.7	—		—	—		—	—		—	1.7
Selling and general expenses		15.8	7.5		2.7	7.4		.8	8.5		.6	43.3

Results of operations before taxes		333.4	207.6		106.4	39.5		45.4	(13.5	)	100.8	819.6
Income tax expenses		115.6	43.3		61.7	35.1		18.5	.8		18.9	293.9

Results of operations (excluding corporate overhead and interest)	$	217.8	164.3		44.7	4.4		26.9	(14.3	)	81.9	525.7

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)	2007		2006	2007	2006
Refining and marketing
North America	$	63.9	115.6	205.6	55.3
United Kingdom		9.3	12.4	27.5	26.0

Total	$	73.2	128.0	233.1	81.3

In the third quarter 2007, the Company’s refining and marketing operations generated a profit of $73.2 million compared to a profit of $128.0 million in the 2006 quarter. Earnings were lower in 2007 due to tighter margins for both refining and marketing operations in North America compared to the 2006 period. In the 2006 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; these costs were mostly associated with unrecoverable repair costs at the Meraux, Louisiana refinery and costs associated with settlement of oil spill class action litigation, and are net of anticipated insurance recoveries. Worldwide petroleum product sales averaged 472,876 barrels per day in 2007, compared to 427,465 barrels per day in the same period in 2006. Worldwide refinery inputs were 176,785 barrels per day in the third quarter of 2007 compared to 170,841 in the 2006 quarter.

In the first nine months of 2007, the Company’s refining and marketing operations reported a profit of $233.1 million compared to a profit of $81.3 million in the 2006 period. The higher income in 2007 compared to 2006 was based on stronger refinery margins in North America and the U.K., higher crude oil throughput at the Meraux refinery, and lower hurricane-related expenses in the United States. The 2006 results included net-of-tax hurricane related costs of $65.1 million. The Meraux refinery was shut down for repairs for the first five months of 2006.

Selected operating statistics for the three-month and nine-month periods ended September 30, 2007 and 2006 follow.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2007	2006	2007	2006
Refinery inputs – barrels per day	176,785	170,841	179,276	108,968
North America	140,886	136,075	145,413	75,182
United Kingdom	35,899	34,766	33,863	33,786
Petroleum products sold – barrels per day	472,876	427,465	444,845	375,982
North America	433,536	392,374	408,064	341,281
Gasoline	312,553	281,168	295,283	263,601
Kerosine	152	284	1,250	2,055
Diesel and home heating oils	88,894	76,239	85,565	56,956
Residuals	16,357	19,318	15,873	10,446
Asphalt, LPG and other	15,580	15,365	10,093	8,223
United Kingdom	39,340	35,091	36,781	34,701
Gasoline	15,023	13,103	12,798	12,341
Kerosine	3,670	4,788	3,499	3,634
Diesel and home heating oils	14,811	11,039	13,036	11,243
Residuals	3,895	4,267	3,549	4,172
LPG and other	1,941	1,894	3,899	3,311

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Corporate and other

The after-tax costs of corporate functions were $24.5 million in the 2007 quarter compared to costs of $22.6 million in the 2006 quarter. The higher costs in 2007 related to more interest expense, caused by higher average debt balances, and higher administrative expenses.

Corporate after-tax costs were $61.6 million in the first nine months of 2007 compared to $50.7 million in the 2006 period. The Company had higher net interest expense in the 2007 period due to higher average debt levels partially offset by higher interest capitalized on development projects. In addition, the Company had after-tax foreign exchange charges of $7.3 million in 2007 compared to charges of $5.6 million in 2006. Higher administrative expenses in 2007 also contributed to higher net corporate costs compared to 2006.

Financial Condition

Net cash provided by operating activities was $915.0 million for the first nine months of 2007 compared to $624.4 million for the same period in 2006. The increase in 2007 was primarily attributable to higher net income, higher non-cash expenses, and a smaller increase in noncash operating working capital compared to the 2006 period. Changes in operating working capital other than cash and cash equivalents used cash of $199.6 million in the first nine months of 2007 and $306.3 million in the first nine months of 2006. This use of cash from operating working capital in 2007 was mostly attributable to increases in accounts receivable and inventories which exceeded higher levels of accounts payable. The use of cash for operating 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. Cash from operating activities was reduced by expenditures for asset retirement obligations totaling $4.6 million in 2007 and $3.1 million in 2006. Proceeds from the sale of assets provided cash of $18.8 million in the first nine months of 2007 compared to $19.8 million in the same period in 2006.

Other predominant uses of cash in each period were for dividends, which totaled $91.8 million in 2007 and $70.1 million in 2006, and for property additions and dry holes, which including amounts expensed, were $1,279.5 million and $884.1 million in the nine-month periods ended September 30, 2007 and 2006, respectively. Total capital expenditures in the nine months of 2007 and 2006 are summarized in the following table.


	Nine Months Ended September 30,
(Millions of dollars)	2007		2006
Capital Expenditures
Exploration and production	$	1,231.4	819.4
Refining and marketing		206.2	131.0
Corporate and other		3.0	4.5

Total capital expenditures	$	1,440.6	954.9

Working capital (total current assets less total current liabilities) at September 30, 2007 was $1,176.9 million, up from $796.0 million at December 31, 2006. This level of working capital includes valuing certain inventories using lower historical costs under LIFO accounting. The carrying value of LIFO inventories was $566.6 million below current costs at September 30, 2007.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Financial Condition (Contd.)

At September 30, 2007, long-term notes payable of $1,493.3 million increased $660.2 million from December 31, 2006. Long-term nonrecourse debt of a subsidiary was $3.2 million, down $4.0 million from December 31, 2006, primarily due to repayments. A summary of capital employed at September 30, 2007 and December 31, 2006 follows.


(Millions of dollars)	September 30, 2007			December 31, 2006
Capital Employed	Amount		%	Amount		%
Notes payable	$	1,493.3	23.4	$	833.1	16.8
Nonrecourse debt of a subsidiary		3.2	0.1		7.2	0.1
Stockholders' equity		4,880.6	76.5		4,121.3	83.1

Total capital employed	$	6,377.1	100.0	$	4,961.6	100.0

The Company’s ratio of earnings to fixed charges was 15.0 to 1 for the nine-month period ended September 30, 2007.

Accounting and Other Matters

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.

Outlook

The significant Kikeh field, offshore Sabah, Malaysia, came on production in mid-August and oil production will continue to expand at this field through 2008 as additional wells are completed and brought online. Crude oil prices remain strong (above $90 per barrel of West Texas Intermediate) in the early portion of the fourth quarter. The Company currently expects its oil and natural gas production to average about 118,000 barrels of oil equivalent per day in the fourth quarter. Downstream margins remain under pressure early in the fourth quarter primarily due to a higher price for crude oil. The Company currently anticipates total capital expenditures of $2.5 billion for the full year 2007, including the anticipated completion of the acquisition of the 70% of the Milford Haven, Wales refinery that it does not already own. See page 10 for discussion about recent announcements regarding enacted changes in government revenue sharing in Ecuador.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Forward-Looking Statements

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

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note H to this Form 10-Q report, Murphy periodically makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions. There were short-term derivative contracts in place at September 30, 2007 to hedge the purchase price of about 1.7 million barrels of crude oil at the Meraux refinery. A 10% increase in the price of West Texas Intermediate crude oil would have increased the liability associated with this derivative contract by approximately $14.3 million, while a 10% decrease would have reduced the 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 changes in the Company’s internal controls over financial reporting during the quarter ended September 30, 2007 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

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 were consolidated with the first suit into a single action in the U.S. District Court for the Eastern District of Louisiana. In September 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. A Fairness Hearing was held January 4, 2007 and the court entered its ruling on January 30, 2007 approving the class settlement. The majority of the settlement of $330 million will be paid by insurance. The Company recorded an expense of $18 million in the second half of 2006 related to settlement costs not expected to be 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. As part of the settlement, the Company undertook to offer to purchase all properties in an agreed area adjacent to the west side of the Meraux refinery; these property purchases and associated remediation are to be paid by the Company and are expected to total $55 million. Approximately 75 non-class action suits regarding the oil spill have been filed and remain pending. The Company believes that insurance coverage exists and it does not expect to incur significant costs associated with this litigation. On August 14, 2007, four of the Company’s high level excess insurers noticed the Company for arbitration in London. The insurers do not deny coverage, but seek arbitration as to whether and to what extent expenditures made by the Company in resolving the oil spill litigation have reached the attachment point for covered loss under their respective policies. The Company is of the position that full coverage should be afforded. Accordingly, the Company believes neither the ultimate resolution of the remaining litigation nor the insurance arbitration will have a material adverse effect on its net income, financial condition or liquidity in a future period.

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.

PART II – OTHER INFORMATION (Contd.)

ITEM 1A.

RISK FACTORS

In addition to the risk factors previously disclosed in its Form 10-K filed on March 1, 2007, the Company’s proved undeveloped reserves and non-producing proved developed reserves represent significant portions of total proved reserves. As of December 31, 2006, approximately 43% of the Company’s proved oil reserves and 79% of proved natural gas reserves are undeveloped. The ability of the Company to reclassify these undeveloped proved reserves to the proved developed classification is generally dependent on the successful completion of one or more operations, which might include further development drilling, construction of facilities or pipelines, and well workovers. Proved undeveloped reserves have inherently more risk than proved developed reserves, generally due to significant development work which is both costly and uncertain as to timing of completion prior to the start of production. Also, at December 31, 2006, the Company’s non-producing proved developed reserves represent approximately 9% of the Company’s total proved reserves on a barrel of oil equivalent basis. These non-producing proved developed reserves are primarily in the U.S. Gulf of Mexico and generally represent “behind pipe” reserves that will require an uphole recompletion to produce the more shallow oil or natural gas reservoir. These “behind pipe” reserves have more risk than producing proved developed reserves.

ITEM 6.

EXHIBITS AND REPORTS ON FORM 8-K

(a)	The Exhibit Index on page 32 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, 2007 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, 2007.

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, Vice President and Controller
		(Chief Accounting Officer and Duly Authorized Officer)

November 7, 2007

(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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