SEC Filing - Murphy Oil Corporation

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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, 2005

¨	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 an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). x Yes ¨ No

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, 2005 was 185,530,931.

MURPHY OIL CORPORATION

TABLE OF CONTENTS


		Page
Part I – Financial Information

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

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk		27

Item 4. Controls and Procedures		27

Part II – Other Information

Item 1. Legal Proceedings		28

Item 6. Exhibits and Reports on Form 8-K		29

Signature		30

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)


	(Unaudited) September 30, 2005			December 31, 2004
ASSETS
Current assets
Cash and cash equivalents	$	531,655		535,525
Short-term investments in marketable securities		—		17,892
Accounts receivable, less allowance for doubtful accounts of $14,210 in 2005 and $13,962 in 2004		839,626		702,933
Inventories, at lower of cost or market
Crude oil and blend stocks		180,151		71,010
Finished products		202,906		155,295
Materials and supplies		74,337		69,540
Prepaid expenses		44,808		45,771
Deferred income taxes		42,036		31,397

Total current assets		1,915,519		1,629,363

Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $2,373,184 in 2005 and $2,933,214 in 2004		4,172,060		3,685,594
Goodwill, net		44,170		43,582
Deferred charges and other assets		111,609		99,704

Total assets	$	6,243,358		5,458,243

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	21,806		50,727
Accounts payable and accrued liabilities		1,143,990		912,329
Income taxes payable		167,263		241,935

Total current liabilities		1,333,059		1,204,991

Notes payable		597,875		597,735
Nonrecourse debt of a subsidiary		11,638		15,620
Deferred income taxes		591,325		577,043
Asset retirement obligations		169,851		201,932
Accrued major repair costs		47,727		44,246
Deferred credits and other liabilities		179,929		167,520

Stockholders’ equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued		—		—
Common Stock, par $1.00, authorized 450,000,000 shares at September 30, 2005 and 200,000,000 shares at December 31, 2004, issued 186,828,618 shares at September 30, 2005 and 94,613,379 shares at December 31, 2004		186,829		94,613
Capital in excess of par value		435,099		511,045
Retained earnings		2,610,609		1,981,020
Accumulated other comprehensive income		130,431		134,509
Unamortized restricted stock awards		(17,187	)	(4,738	)
Treasury stock, 1,297,687 shares of Common Stock in 2005 and 2,578,002 shares in 2004, at cost		(33,827	)	(67,293	)

Total stockholders’ equity		3,311,954		2,649,156


Total liabilities and stockholders’ equity	$	6,243,358		5,458,243

See Notes to Consolidated Financial Statements on 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,
	2005			2004¹		2005		2004¹
REVENUES
Sales and other operating revenues	$	3,311,332		2,262,288		8,487,045		5,987,494
Gain on sale of assets		6,247		39,100		178,171		69,900
Interest and other income (loss)		(660	)	(7,933	)	16,517		1,480

Total revenues		3,316,919		2,293,455		8,681,733		6,058,874

COSTS AND EXPENSES
Crude oil and product purchases		2,546,896		1,732,904		6,302,891		4,428,926
Production and operating expenses		210,605		171,035		641,035		519,471
Exploration expenses, including undeveloped lease amortization		32,863		70,118		143,168		142,476
Net costs associated with hurricanes		34,054		3,350		34,054		3,350
Selling and general expenses		41,091		33,622		117,855		97,497
Depreciation, depletion and amortization		93,769		75,594		307,562		238,504
Accretion of asset retirement obligations		2,271		2,575		7,403		7,549
Interest expense		12,238		13,858		35,775		42,325
Interest capitalized		(10,834	)	(6,017	)	(27,156	)	(15,083	)

Total costs and expenses		2,962,953		2,097,039		7,562,587		5,465,015

Income from continuing operations before income taxes		353,966		196,416		1,119,146		593,859
Income tax expense		131,567		80,643		435,801		229,255

Income from continuing operations		222,399		115,773		683,345		364,604
Income from discontinued operations, net of tax		8,549		2,950		8,549		202,231

NET INCOME	$	230,948		118,723		691,894		566,835

INCOME PER COMMON SHARE – BASIC²
Income from continuing operations	$	1.20		.63		3.71		1.98
Income from discontinued operations		.05		.01		.05		1.10

NET INCOME – BASIC	$	1.25		.64		3.76		3.08

INCOME PER COMMON SHARE – DILUTED²
Income from continuing operations	$	1.18		.62		3.64		1.95
Income from discontinued operations		.05		.01		.05		1.09

NET INCOME – DILUTED	$	1.23		.63		3.69		3.04

Average common shares outstanding – basic²		184,355,365		184,011,626		184,083,392		183,944,854
Average common shares outstanding – diluted²		188,069,208		187,136,842		187,740,260		186,731,094

¹	Reclassified to conform to 2005 presentation.

²	Income per common share and average common shares outstanding for 2004 periods reflect a two-for-one stock split effective June 3, 2005.

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,
	2005			2004		2005		2004
Net income	$	230,948		118,723		691,894		566,835

Other comprehensive income, net of tax
Cash flow hedges
Net derivative gains (losses)		(2,716	)	(411	)	(22,017	)	3,957
Reclassification adjustments		(246	)	(3,115	)	(950	)	(8,589	)

Total cash flow hedges		(2,962	)	(3,526	)	(22,967	)	(4,632	)
Net gain from foreign currency translation		33,393		44,211		18,889		30,788

COMPREHENSIVE INCOME	$	261,379		159,408		687,816		592,991

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,
	2005			2004
OPERATING ACTIVITIES
Income from continuing operations	$	683,345		364,604
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Depreciation, depletion and amortization		307,562		238,504
Provisions for major repairs		27,310		22,692
Expenditures for major repairs and asset retirement obligations		(30,249	)	(14,700	)
Dry hole expense		63,992		100,370
Amortization of undeveloped leases		17,519		11,705
Accretion of asset retirement obligations		7,403		7,549
Deferred and noncurrent income tax charges		20,077		96,765
Pretax gains from disposition of assets		(178,171	)	(69,900	)
Net (increase) decrease in operating working capital other than cash and cash equivalents		(150,929	)	59,071
Other		(6,688	)	(6,817	)

Net cash provided by continuing operations		761,171		809,843
Net cash provided by discontinued operations		8,549		60,800

Net cash provided by operating activities		769,720		870,643

INVESTING ACTIVITIES
Property additions and dry hole costs		(881,130	)	(731,138	)
Proceeds from the sales of assets		173,629		59,538
Proceeds from maturities of marketable securities		17,892		—
Other – net		(5,222	)	(453	)
Investing activities of discontinued operations
Sales proceeds		—		582,675
Other		—		(9,619	)

Net cash required by investing activities		(694,831	)	(98,997	)

FINANCING ACTIVITIES
Repayments of notes payable		(29,065	)	(27,592	)
Repayments of nonrecourse debt of a subsidiary		(4,193	)	(36,970	)
Proceeds from exercise of stock options and employee stock purchase plans		18,731		2,178
Cash dividends paid		(62,305	)	(57,496	)
Other		(1,052	)	—

Net cash used in financing activities		(77,884	)	(119,880	)

Effect of exchange rate changes on cash and cash equivalents		(875	)	50,938

Net increase (decrease) in cash and cash equivalents		(3,870	)	702,704
Cash and cash equivalents at January 1		535,525		252,425

Cash and cash equivalents at September 30	$	531,655		955,129

SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid, net of refunds	$	423,217		115,813

Interest paid, net of amounts capitalized		—		15,679

Interest capitalized in excess of interest paid		3,591		—

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,
	2005			2004
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued		—		—

Common Stock – par $1.00, authorized 450,000,000 shares at September 30, 2005 and 200,000,000 shares at September 30, 2004, issued 186,828,618 shares at September 30, 2005 and 94,613,379 shares at September 30, 2004
Balance at beginning of period	$	94,613		94,613
Two-for-one stock split effective June 3, 2005		92,216		—

Balance at end of period		186,829		94,613

Capital in Excess of Par Value
Balance at beginning of period		511,045		504,809
Exercise of stock options, including income tax benefits		1,273		229
Restricted stock transactions and other		14,435		4,572
Sale of stock under employee stock purchase plans		562		678
Two-for-one stock split effective June 3, 2005		(92,216	)	—

Balance at end of period		435,099		510,288

Retained Earnings
Balance at beginning of period		1,981,020		1,357,910
Net income for the period		691,894		566,835
Cash dividends		(62,305	)	(57,496	)

Balance at end of period		2,610,609		1,867,249

Accumulated Other Comprehensive Income
Balance at beginning of period		134,509		65,246
Foreign currency translation gains, net of income taxes		18,889		30,788
Cash flow hedging losses, net of income taxes		(22,967	)	(4,632	)

Balance at end of period		130,431		91,402

Unamortized Restricted Stock Awards
Balance at beginning of period		(4,738	)	—
Stock awards		(16,344	)	(5,160	)
Amortization, forfeitures and changes in price of Common Stock		3,895		(247	)

Balance at end of period		(17,187	)	(5,407	)

Treasury Stock
Balance at beginning of period		(67,293	)	(71,695	)
Exercise of stock options		28,584		980
Sale of stock under employee stock purchase plans		550		510
Awarded restricted stock, net of forfeitures		4,332		2,217

Balance at end of period		(33,827	)	(67,988	)

Total Stockholders’ Equity	$	3,311,954		2,490,157

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, 2004. 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, 2005, and the results of operations and cash flows for the three-month and nine-month periods ended September 30, 2005 and 2004, in conformity with accounting principles generally accepted in the United States. In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the United States of America, management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.

Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2004 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the nine months ended September 30, 2005 are not necessarily indicative of future results. Certain 2004 amounts included in the consolidated financial statements have been reclassified to conform to the 2005 presentation.

Note B – Discontinued Operations

The Company sold most of its Western Canadian conventional oil and gas assets (sale properties) in the second quarter 2004 for net proceeds of $583 million. At the time of the sale, the sale properties produced about 20,000 barrels of oil equivalent per day. The operating results from the sale properties have been reported as discontinued operations in 2004.

The following table reflects the results of discontinued operations including the 2004 gain on sale.


(Thousands of dollars)	Three Months Ended September 30, 2004		Nine Months Ended September 30, 2004
Revenues, including a pretax gain on sale of assets of $194,440 in the nine-month period ended September 30, 2004	$	4,638	274,610
Income before income tax expense		5,490	243,572
Income tax expense		2,540	41,341

In the third quarter of 2005, the Company’s Canadian subsidiary recorded an $8.6 million income tax benefit associated with the sale of Western Canadian assets in 2004. The benefit was the result of a change in a previous estimate.

Note C – Property, Plant and Equipment

In June 2005, the Company completed the sale of mature oil and natural gas properties on the continental shelf of the Gulf of Mexico for a sale price of approximately $156.3 million after operating adjustments. Total daily net production from the properties sold amounted to approximately 4,400 barrels of oil equivalent prior to the sale, and total net proved reserves at December 31, 2004 were 35.8 billion cubic feet of natural gas and 1.5 million barrels of oil. The assets sold had a net book value of $33.5 million and an associated asset retirement obligation liability of $44.8 million. The Company recorded a gain before income taxes of approximately $168.9 million on this transaction. In September 2005, the Company’s Canadian subsidiary sold an existing heavy oil field in the Winter area and recorded a $6 million pre-tax gain on this transaction. Both transactions are included in Gain on Sale of Assets on the Consolidated Statement of Income in the respective periods inclusive of the sale transaction.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

During the nine months ended September 30, 2004, the Company reported before tax gains of $69.9 million on sale of assets. The primary assets sold were certain natural gas fields onshore United States, all but one of the Company’s jointly owned marketing terminals in the United States and the “T” Block field in the U.K. section of the North Sea.

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

At September 30, 2005, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $240 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2005 and 2004.


(Thousands of dollars)	2005		2004
Beginning balance at January 1	$	106,105	158,034
Additions pending the determination of proved reserves		133,911	95,296
Reclassifications to proved properties based on the determination of proved reserves		—	—
Capitalized exploratory well costs charged to dry hole expense or sold		—	(20,766	)

Ending balance at September 30	$	240,016	232,564

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)	2005		2004
Capitalized exploratory well costs capitalized for one year or less	$	151,640	133,862
Capitalized exploratory well costs capitalized for more than one year but less than two years		76,211	98,702
Capitalized exploratory well costs capitalized for more than two years but less than three years		12,165	—

Balance at September 30	$	240,016	232,564

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

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 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

The table that follows provides the components of net periodic benefit expense for the three-month and nine-month periods ended September 30, 2005 and 2004.


	Three Months Ended September 30,
	2005			2004		2005		2004
(Thousands of dollars)	Pension Benefits					Postretirement Benefits
Service cost	$	2,418		1,916		460		316
Interest cost		5,404		4,774		940		856
Expected return on plan assets		(4,974	)	(4,705	)	—		—
Amortization of prior service cost		59		(50	)	(68	)	(180	)
Amortization of transitional asset		(4	)	100		—		—
Recognized actuarial loss		1,689		1,198		435		455

		4,592		3,233		1,767		1,447
Settlement gain		—		(507	)	—		—

Net periodic benefit expense	$	4,592		2,726		1,767		1,447


	Nine Months Ended September 30,
	2005			2004		2005		2004
(Thousands of dollars)	Pension Benefits					Postretirement Benefits
Service cost	$	6,997		6,593		1,400		994
Interest cost		15,033		14,663		2,714		2,694
Expected return on plan assets		(14,121	)	(14,197	)	—		—
Amortization of prior service cost		177		(189	)	(203	)	(566	)
Amortization of transitional asset		(36	)	303		—		—
Recognized actuarial loss		4,208		3,338		1,119		1,433

		12,258		10,511		5,030		4,555
Settlement gain		—		(1,041	)	—		—

Net periodic benefit expense	$	12,258		9,470		5,030		4,555

Murphy previously disclosed in its financial statements for the year ended December 31, 2004, that it expected to make required and discretionary contributions totaling $12.1 million to its defined benefit pension plans and $2.9 million to its postretirement benefits plan during 2005. During the nine-month period ended September 30, 2005, the Company made contributions to its domestic and foreign defined benefit pension and postretirement plans of $12.2 million. In the third quarter, the Company approved an additional $14.5 million discretionary contribution to its domestic defined benefit pension plans that will be paid before year end. In addition to the $14.5 million discretionary contribution, remaining funding in 2005 for these plans is currently anticipated to be $2.8 million.

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) will provide prescription drug coverage under Medicare beginning in 2006. Generally, companies that provide qualifying prescription drug coverage that is deemed actuarially equivalent to Medicare coverage for retirees aged 65 and above will be eligible to receive a federal subsidy equal to 28% of drug costs between $250 and $5,000 per annum for each covered individual that does not elect to receive coverage under the new prescription drug Medicare Part D. The Company currently provides prescription drug coverage to qualifying retirees under its retiree medical plan. The Company recognized $1 million and $.7 million in estimated benefits related to the Act in the nine-month periods ended September 30, 2005 and 2004, respectively.

Note E – Financing Arrangements

On June 14, 2005, Murphy entered into a five-year $1 billion committed credit facility, whereby the Company and certain wholly-owned subsidiaries may borrow funds from a major banking consortium. The new credit facility replaced two similar committed credit facilities with an aggregate borrowing capacity of $700 million. Borrowings under the new credit facility bear interest at prime or varying cost of fund options. Facility fees are due on the commitments. No amounts had been borrowed under this credit facility as of September 30, 2005.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note F – Financial Instruments and Risk Management

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

•

Natural Gas Fuel Price Risks – The Company purchases natural gas as fuel at its Meraux, Louisiana refinery, and as such, is subject to commodity price risk related to the purchase price of this gas. Murphy has hedged the cash flow risk associated with the cost of a portion of the natural gas it will purchase in 2005 and 2006 by entering into financial contracts known as natural gas swaps with a remaining notional volume as of September 30, 2005 of 1.1 million MMBTU (million British Thermal Units). Under the natural gas swaps, the Company pays a fixed rate averaging $3.35 per MMBTU and receives a floating rate in each month of settlement based on the average NYMEX price for the final three trading days of the month. Murphy has a risk management control system to monitor natural gas price risk attributable both to forecasted natural gas requirements and to Murphy’s natural gas swaps. The control system involves using analytical techniques, including various correlations of natural gas purchase prices to future prices, to estimate the impact of changes in natural gas fuel prices on Murphy’s cash flows. The fair value of the effective portions of the natural gas swaps and changes thereto is deferred in Accumulated Other Comprehensive Income (AOCI) and is subsequently reclassified into Crude Oil and Product Purchases in the income statements in the periods in which the hedged natural gas fuel purchases affect earnings. During the nine-month periods ended September 30, 2005 and 2004, the Company received approximately $4.1 million and $14.5 million, respectively, for maturing swap agreements. For the three-month and nine-month periods ended September 30, 2004, the income effect from cash flow hedging ineffectiveness for these contracts was insignificant. In September 2005, the Company determined that approximately .4 million MMBTU of contracts maturing in 2005 would no longer qualify as a cash flow hedge since the purchase of this gas was no longer anticipated to occur while the Meraux refinery was temporarily idled after Hurricane Katrina. Gains of $1.5 million were recognized in earnings in the third quarter of 2005 as a result of the contracts no longer qualifying as a cash flow hedge.

•

Crude Oil Sales Price Risks – The sales price of crude oil produced by the Company is subject to commodity price risk. Murphy has hedged the cash flow risk associated with the sales price for a portion of its Canadian heavy oil production during 2005 and 2006 by entering into forward sale contracts covering a notional volume of approximately 2,000 barrels per day in 2005 and 4,000 barrels per day in 2006. The Company will pay the average of the posted price for blended heavy oil at the Hardisty terminal in Canada for each month and receive at that location a fixed price of $29.00 per barrel in 2005 and $25.23 per barrel in 2006. Murphy has a risk management control system to monitor crude oil price risk attributable both to forecasted crude oil sales prices and to Murphy’s hedging instruments. The control system involves using analytical techniques, including various correlations of crude oil sales prices to future prices, to estimate the impact of changes in crude oil prices on Murphy’s cash flows from the sale of heavy crude oil. The fair values of the effective portions of the crude oil hedges and changes thereto are deferred in AOCI and are subsequently reclassified into Sales and Other Operating Revenues in the income statement in the periods in which the hedged crude oil sales affect earnings. In the nine-month period ended September 30, 2005, cash flow hedging ineffectiveness relating to the crude oil sales swaps reduced Murphy’s after-tax earnings by less than $.1 million. During the nine-month period ended September 30, 2005 the Company paid approximately $3.9 million for settlement of maturing forward sale contracts. The fair value of the crude oil sales swaps is based on the average fixed price of the instruments and the published NYMEX index futures price or crude oil price quotes from counterparties.

•

Interest Rate Risks – When Murphy borrows under existing credit facilities, it enters into variable-rate debt obligations that expose the Company to the effects of changes in interest rates. To partially reduce its exposure to interest rate risk, Murphy had interest rate swap agreements with notional amounts totaling $15 million at September 30, 2004 to hedge fluctuations in cash flows of a similar amount of variable rate debt. The swaps matured in October 2004. Under the interest rate swaps, the Company paid fixed rates averaging 6.06% over their composite lives and received variable rates which averaged 1.68% at September 30, 2004. For the nine-month period ended September 30, 2004, the income effect from cash flow hedging ineffectiveness of interest rates was insignificant.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

During the next 12 months, the Company expects to reclassify approximately $17 million in net after-tax losses from AOCI into earnings as the forecasted transactions covered by hedging instruments actually occur. All forecasted transactions currently being hedged are expected to occur by December 2006.

Note G – Earnings per Share and Stock Options

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, 2005 and 2004. The number of shares and per share amounts presented for 2005 and 2004 reflect the Company’s two-for-one stock split effective June 3, 2005. The following table reconciles the weighted-average shares outstanding used for these computations.


	Three Months Ended September 30,		Nine Months Ended September 30,
(Weighted-average shares)	2005	2004	2005	2004
Basic method	184,355,365	184,011,626	184,083,392	183,944,854
Dilutive stock options	3,713,843	3,125,216	3,656,868	2,786,240

Diluted method	188,069,208	187,136,842	187,740,260	186,731,094

There were no antidilutive stock options for the three-month and nine-month periods ended September 30, 2005 and 2004.

The Company uses the intrinsic-value based method to account for its stock options as prescribed by Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Under this method, no compensation expense is recorded for fixed stock options since all option prices have been equal to or greater than the fair market value of the Company’s stock on the date of grant. The Company accrues costs of restricted stock and any stock option deemed to be variable in nature over the vesting/performance period and adjusts such costs for changes in the fair market value of Common Stock. The FASB has issued SFAS No. 123 (revised 2004), Share-Based Payment, which replaces SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB No. 25. SFAS No. 123 (revised 2004) 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. In April 2005, the Securities and Exchange Commission adopted a new rule allowing the Company to defer implementation of this statement until January 1, 2006. The Company is currently evaluating which fair value measurement method to use in 2006 and whether to use the modified retrospective application or modified prospective application upon adoption. Had the Company recorded compensation expense for stock options as prescribed by SFAS No. 123, net income and earnings per share for the three-month and nine-month periods ended September 30, 2005 and 2004, would be the pro forma amounts shown in the following table.


	Three Months Ended September 30,					Nine Months Ended September 30,
(Thousands of dollars except per share data)	2005			2004		2005		2004
Net income – As reported	$	230,948		118,723		691,894		566,835
Restricted stock compensation expense included in income, net of tax		1,471		382		4,044		893
Total stock-based compensation expense using fair value method for all awards, net of tax		(2,330	)	(1,602	)	(7,913	)	(4,623	)

Net income – Pro forma	$	230,089		117,503		688,025		563,105

Net income per share –
As reported, basic	$	1.25		.64		3.76		3.08
Pro forma, basic		1.25		.64		3.74		3.06
As reported, diluted		1.23		.63		3.69		3.03
Pro forma, diluted		1.22		.63		3.66		3.02

In the first quarter 2005, the Company granted 935,000 stock options with an exercise price of $45.225 per share, and also awarded 358,950 shares of performance-based and time-based restricted stock.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note H – Hurricane Related Matters

In September 2005 the Company recorded pretax costs of $34.1 million ($21.3 million after taxes) associated with hurricanes that occurred in the United States. These costs are net of anticipated insurance recoveries. The components of these costs include $13.8 million for incremental insurance expenses; $3.0 million for uninsured losses within the Company’s insurance deductibles; $8.9 million for voluntary costs for charitable donations related to hurricane relief efforts and additional employee salaries; $5.1 million for depreciation and salaries for the temporarily idled Meraux, Louisiana, refinery; and $3.3 million for other incremental expenses incurred that are not covered by insurance policies. The Company anticipates that additional costs related to Hurricanes Katrina and Rita will be recorded in future periods. The costs are reported in “Net costs associated with hurricanes” in the Consolidated Statements of Income. See Note J for additional information regarding environmental and other contingencies relating to Hurricane Katrina.

Also in the third quarter of 2005, the Company’s U.S. exploration and production operations recorded $7.6 million in business interruption insurance recoveries ($11.2 million in the first nine months of 2005) relating to prior-year hurricanes. The income was reported in “Sales and other operating revenues” in the Consolidated Statements of Income.

Note I – Accumulated Other Comprehensive Income

The components of Accumulated Other Comprehensive Income on the Consolidated Balance Sheets at September 30, 2005 and December 31, 2004 are presented in the following table.


(Thousands of dollars)	September 30, 2005			December 31, 2004
Foreign currency translation gain, net	$	186,551		167,662
Cash flow hedging, net		(18,385	)	4,582
Minimum pension liability, net		(37,735	)	(37,735	)

Accumulated other comprehensive income	$	130,431		134,509

The effect of SFAS Nos. 133/138, Accounting for Derivative Investments and Hedging Activities, decreased AOCI for the nine months ended September 30, 2005 by $22.9 million, net of $9.7 million in income taxes, and hedging ineffectiveness increased income by $1 million, net of $.5 million in income taxes. The ineffectiveness was the result of a portion of swaps no longer qualifying as a cash flow hedge (see Note F). The AOCI decrease in the nine-month period ended September 30, 2005 was primarily related to the change in fair value of blended heavy oil forward sales contracts described in Note F. Derivative instruments decreased AOCI for the nine months ended September 30, 2004 by $4.6 million, net of $2.2 million in income taxes, and hedging ineffectiveness decreased income by less than $.1 million.

Note J – Environmental and Other Contingencies

The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax increases and retroactive tax claims; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Because governmental actions are often motivated by political considerations 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.

The Company is subject to numerous laws and regulations intended to protect the environment and/or impose remedial obligations and it 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 80 service stations for which known or potential obligations for environmental remediation exist.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Environmental and Other Contingencies (Contd.)

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 within the Company’s asset retirement obligation liability.

A provision for environmental obligations is charged to expense when a liability for an environmental assessment and/or cleanup is probable and the cost can be reasonably estimated. Related expenditures are charged against the liability. Environmental remediation liabilities have not been discounted for the time value of future expected payments.

A release of crude oil occurred at the Company’s Meraux, Louisiana, refinery as a result of damage to a crude oil storage tank caused by Hurricane Katrina. A number of class action lawsuits have been filed and consolidated into a single action in federal court in the Eastern District of Louisiana seeking unspecified damages from a Company subsidiary and/or the Company and class status for residents affected by the spill. The Company has engaged experts to assess and test the areas affected by the crude oil spill. Nearly all the oil that leaked from the tank has been recovered or has evaporated and the clean up of public areas is nearly complete. The Company is in the process of discussing settlements with affected residents and the clean up of the oil on private property will be done with the owner’s permission. Due to numerous uncertainties surrounding the ultimate cleanup of the site and the settlement of the lawsuits, the Company is unable to estimate a potential range of costs that may be ultimately incurred to remediate the site and settle with property owners. The Company has recorded a cost of $2 million, included in “Net costs associated with hurricanes” in the Consolidated Statements of Income as of September 30, 2005, related to the insurance deductible associated with this incident. The Company believes that insurance coverage exists for this release and the lawsuits, and the ultimate costs for cleanup of the site and resolution of the class action lawsuits will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

The Company’s liability for environmental 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 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 to be incurred at known or currently unidentified sites is not expected to have a material adverse effect on its net income, financial condition or liquidity in a future period.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Environmental and Other Contingencies (Contd.)

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

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

In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide financial guarantees or letters of credit that may be drawn upon if the Company fails to perform under those contracts. At September 30, 2005, the Company had contingent liabilities of $8.5 million under a financial guarantee and $246 million on outstanding letters of credit. The majority of these letters of credit relate to crude oil cargo purchases by the Company’s Meraux refinery. The Company has not accrued a liability in its balance sheet related to the guarantee and letters of credit because it believes that the likelihood of having these drawn is remote.

Note K – Commitments

To assure long-term supply of hydrogen at its Meraux, Louisiana refinery, the Company had contracted to purchase up to 35 million standard cubic feet of hydrogen per day at market prices through 2019. The contract requires the payment of a base facility charge for use of the facility. As a result of the refinery being shut down for several months following Hurricane Katrina, the Company has notified the hydrogen supplier of a force majeure event. The hydrogen supply agreement permits the base facility charge to be suspended for the period under force majeure and the contract supply period to be extended for the same period, but in no event shall the extension of the supply period exceed 1,375 days. The Company currently expects to complete repairs to its refinery and begin purchasing hydrogen under this agreement within the period permitted in the contract.

Note L – Accounting Matters

In October 2004 the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (the “Act”) became law. The FASB issued FSP 109-1 in December 2004 to provide guidance on the application of SFAS No. 109, Accounting for Income Taxes, to the provision within the Act that will ultimately provide a tax deduction of up to 9% on qualified production activities. The tax deduction phases in at 3% beginning in 2005 and reaches 9% in 2010. FSP 109-1 concluded that the deduction should be accounted for as a special deduction in accordance with SFAS 109, whereby the tax benefit is recognized as realized, rather than as a one-time benefit due to a reduction of deferred tax liabilities. This FSP was effective upon issuance. The Company recorded a tax benefit of approximately $3.1 million in the nine-month period ended September 30, 2005 related to the Act.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note L – Accounting Matters (Contd.)

The EITF has issued EITF 03-13, Applying the Conditions in Paragraph 42 of SFAS No. 144 in Determining Whether to Report Discontinued Operations. The EITF generally believes that current practice with respect to applying the criteria in paragraph 42 of SFAS No. 144 has not been applied consistently and has not resulted in broadening the reporting of asset dispositions as discontinued operations. EITF 03-13 contains further guidance for evaluating the cash flows of the component sold and what constitutes significant continuing involvement. This standard must be applied to all asset disposal transactions occurring after January 1, 2005. In certain industries, EITF 03-13 may lead to more asset disposals being reported as discontinued operations in future periods. However, in the oil and gas industry, it may cause more asset disposals to continue to be classified as continuing operations due to clarification of what constitutes continuing involvement.

The FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets an amendment of APB Opinion No. 29, in December 2004. This statement addresses the measurement of exchanges of nonmonetary assets and eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. SFAS No. 153 was effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The provisions of this statement are applied prospectively. The adoption of this statement did not have any impact on the Company’s 2005 results of operations.

SFAS No. 151, Inventory Costs, was issued by the FASB in November 2004. This statement amends Accounting Research Bulletin No. 43 to clarify that abnormal amounts of idle facility expense, freight, handling costs, and wasted materials should be recognized as current-period charges, and it also requires that allocation of fixed production overheads be based on the normal capacity of the related production facilities. The provisions of this statement will be effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The provisions of this statement will be applied prospectively. The Company does not expect the adoption of this statement to have a significant impact on its results of operations.

In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS No. 143. This interpretation clarifies the term conditional asset retirement obligation as used in SFAS No. 143 and when a company would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. This interpretation is effective for fiscal years ending after December 15, 2005. The Company is currently evaluating whether the adoption of this interpretation will have any effect on its financial statements.

In March 2005, the Emerging Issues Task Force decided in Issue 04-6, Accounting for Stripping Costs Incurred during Production in the Mining Industry, that mining operations should account for post-production stripping costs as a variable production cost that should be considered a component of mineral inventory costs. The Company’s synthetic oil operations at Syncrude may be affected by this ruling. The EITF consensus is effective for fiscal years beginning after December 15, 2005 and any adjustment required as of the January 1, 2006 effective application date for the Company will be recorded as a cumulative effect of a change in accounting principle. The Company is currently evaluating the accounting implications of this new EITF consensus.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note M – Business Segments


			Three Months Ended September 30, 2005					Three Months Ended September 30, 2004
(Millions of dollars)	Total Assets at Sept. 30, 2005		External Revenues		Inter- segment Revenues	Income (Loss)		External Revenues		Inter- segment Revenues	Income (Loss)
Exploration and production*
United States	$	841.1	168.0		—	71.3		104.4		—	33.0
Canada		1,495.1	211.3		16.5	98.2		136.3		17.8	52.8
United Kingdom		189.0	40.6		—	15.2		81.0		—	42.8
Ecuador		149.1	30.3		—	13.3		.4		—	(.1	)
Malaysia		792.4	62.4		—	10.6		53.4		—	(7.0	)
Other		46.5	.8		—	(4.0	)	.9		—	(2.9	)

Total		3,513.2	513.4		16.5	204.6		376.4		17.8	118.6

Refining and marketing
North America		1,773.0	2,512.2		—	11.2		1,752.1		—	12.9
United Kingdom		356.4	292.0		—	20.8		172.9		—	5.8

Total		2,129.4	2,804.2		—	32.0		1,925.0		—	18.7

Total operating segments		5,642.6	3,317.6		16.5	236.6		2,301.4		17.8	137.3
Corporate		600.7	(.7	)	—	(14.2	)	(7.9	)	—	(21.5	)

Total from continuing operations		6,243.3	3,316.9		16.5	222.4		2,293.5		17.8	115.8
Discontinued operations		—	—		—	8.6		—		—	2.9

Total	$	6,243.3	3,316.9		16.5	231.0		2,293.5		17.8	118.7



	Nine Months Ended September 30, 2005					Nine Months Ended September 30, 2004
(Millions of dollars)	External Revenues		Inter- segment Revenues	Income (Loss)		External Revenues	Inter- segment Revenues	Income (Loss)
Exploration and production*
United States	$	717.5	—	321.1		367.4	—	117.2
Canada		534.9	42.2	232.2		391.3	53.8	170.9
United Kingdom		129.4	—	52.9		161.1	—	72.4
Ecuador		73.3	—	25.8		30.5	—	6.6
Malaysia		185.4	—	22.5		122.9	—	(.4	)
Other		2.6	—	(35.1	)	2.5	—	(7.1	)

Total		1,643.1	42.2	619.4		1,075.7	53.8	359.6

Refining and marketing
North America		6,399.6	—	62.6		4,504.0	—	29.8
United Kingdom		622.5	—	31.3		477.7	—	22.0

Total		7,022.1	—	93.9		4,981.7	—	51.8

Total operating segments		8,665.2	42.2	713.3		6,057.4	53.8	411.4
Corporate		16.5	—	(30.0	)	1.5	—	(46.8	)

Total from continuing operations		8,681.7	42.2	683.3		6,058.9	53.8	364.6
Discontinued operations		—	—	8.6		—	—	202.2

Total	$	8,681.7	42.2	691.9		6,058.9	53.8	566.8

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

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

Results of Operations

Murphy’s net income in the third quarter of 2005 was $231 million, $1.23 per diluted share, compared to net income of $118.7 million, $.63 per diluted share, in the third quarter of 2004. Net income in the current period included income from discontinued operations of $8.6 million, $.05 per share, related to an adjustment of prior-year income taxes associated with the gain on the sale of most of the Company’s conventional oil and gas assets in Western Canada in the second quarter 2004. Income from discontinued operations in the third quarter of 2004 was $2.9 million, $.01 per share. Income from continuing operations in the 2005 third quarter was $222.4 million, $1.18 per diluted share, compared to $115.8 million, $.62 per diluted share, in the same period of 2004, which included a $24.6 million after-tax gain on sale of the “T” Block field in the U.K. North Sea. The 2005 period’s income from continuing operations included pretax costs of $34.1 million ($21.3 million after taxes) associated with hurricanes that occurred in the United States during the just completed quarter. These costs are net of anticipated insurance recoveries. The components of these costs include $13.8 million for incremental insurance expenses; $3.0 million for uninsured losses within the Company’s insurance deductibles; $8.9 million of voluntary costs for Company donations related to hurricane relief efforts and additional employee salaries; $5.1 million for depreciation and salaries for the temporarily idled Meraux, Louisiana, refinery; and $3.3 million for other incremental expenses incurred that are not covered by insurance policies. The Company anticipates that additional costs related to Hurricanes Katrina and Rita will be recorded in future periods.

For the nine months of 2005, net income totaled $691.9 million, $3.69 per diluted share, compared to $566.8 million, $3.04 per diluted share, for the 2004 period. Continuing operations earned $683.3 million, $3.64 per diluted share, in 2005 and $364.6 million, $1.95 per diluted share, in 2004. Income from discontinued operations was $8.6 million, $.05 per diluted share, in the nine months of 2005, while the same period in 2004 totaled $202.2 million, $1.09 per diluted share. Income from discontinued operations in 2004 included a $169.2 million after-tax gain on sale of assets in Western Canada. Murphy’s income by operating segment is presented below.


	Income (Loss)
	Three Months Ended September 30,					Nine Months Ended September 30,
(Millions of dollars)	2005			2004		2005		2004
Exploration and production	$	204.6		118.6		619.4		359.6
Refining and marketing		32.0		18.7		93.9		51.8
Corporate		(14.2	)	(21.5	)	(30.0	)	(46.8	)

Income from continuing operations		222.4		115.8		683.3		364.6
Income from discontinued operations, net of tax		8.6		2.9		8.6		202.2

Net income	$	231.0		118.7		691.9		566.8

The Company’s income contribution from continuing exploration and production operations was $204.6 million in the third quarter of 2005 compared to $118.6 million in the same quarter of 2004. The earnings improvement in 2005 was primarily caused by higher oil and natural gas sales prices, higher oil sales volumes, lower dry hole costs, and after-tax business interruption insurance recoveries of $4.8 million related to prior-year hurricanes. These were partly offset by lower natural gas sales volumes, higher hurricane-related costs in 2005 of $9 million ($11.6 million in 2005 compared to $2.6 million in 2004) and an after-tax gain of $24.6 million in the 2004 period from sale of the “T” Block field in the U.K. North Sea. The Company’s refining and marketing operations generated a profit of $32 million in the most recent quarter compared to a profit of $18.7 million in the 2004 quarter. The earnings improved due to higher profits in the U.K in the 2005 period, partially offset by lower profits in North America. Murphy’s downstream business incurred after-tax costs related to hurricanes of $13.9 million in the just completed quarter ($22.1 million before income taxes). The Company’s Meraux, Louisiana, refinery experienced flooding following Hurricane Katrina and was shut down for the last 34 days of the quarter. The after-tax costs of the corporate functions were $14.2 million in the 2005 quarter compared to costs of $21.5 million in the 2004 quarter. The 2005 period included after-tax costs for foreign exchange of $2.7 million, while the 2004 period included costs of $8.2 million for foreign exchange. In addition, the Company incurred less net interest expense due to lower average debt and a higher portion of interest costs being capitalized in the 2005 period. Higher administrative expenses in 2005, mostly due to higher employee compensation, partially offset lower net foreign exchange and interest expenses.

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

Results of Operations (Contd.)

Income from both the exploration and production and refining and marketing businesses was significantly higher in the first nine months of 2005 compared to the same period in 2004. The Company’s exploration and production continuing operations earned $619.4 million in the nine months of 2005 and $359.6 million in the same period of 2004. The primary reasons for the improved earnings in this business in 2005 were higher oil and natural gas sales prices, higher oil sales volumes, a $106.8 million after-tax gain on sale of mature oil and gas properties on the continental shelf of the Gulf of Mexico, and $7 million in after-tax business interruption insurance recoveries. After-tax costs associated with hurricanes were $5.6 million higher in the 2005 period compared to 2004. Exploration expenses were $143.2 million in 2005 compared to $142.5 million in 2004. The Company’s refining and marketing operations generated a profit of $93.9 million in the first nine months of 2005 compared to a profit of $51.8 million in 2004. The improved current year result was based on better margins in both the North American and U.K. businesses in 2005. The 2005 results for refining and marketing included net-of-tax hurricane related costs of $13.9 million. The Meraux refinery was shut down in September 2005 related to damages caused by Hurricane Katrina. Corporate after-tax costs were $30.0 million in the first nine months of 2005 compared to $46.8 million in the 2004 period. The Company had lower net interest expense in the 2005 period due to a combination of lower average debt levels and higher interest capitalized on development projects. The 2005 period included after-tax foreign exchange charges of $2.4 million, while 2004 included after-tax foreign exchange charges of $7.8 million. Higher administrative expenses in 2005, primarily related to employee compensation costs, partially offset lower interest and foreign exchange expenses.

Exploration and Production

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


	Income (Loss)
	Three Months Ended September 30,					Nine Months Ended September 30,
(Millions of dollars)	2005			2004		2005		2004
Exploration and production
United States	$	71.3		33.0		321.1		117.2
Canada		98.2		52.8		232.2		170.9
United Kingdom		15.2		42.8		52.9		72.4
Ecuador		13.3		(.1	)	25.8		6.6
Malaysia		10.6		(7.0	)	22.5		(.4	)
Other		(4.0	)	(2.9	)	(35.1	)	(7.1	)

Total	$	204.6		118.6		619.4		359.6

Exploration and production operations in the United States reported earnings of $71.3 million in the third quarter of 2005 compared to earnings of $33 million a year ago. The earnings improvement in 2005 was primarily caused by higher oil and natural gas sales prices, higher oil sales volumes, lower dry hole costs, and after-tax business interruption insurance recoveries of $4.8 million after taxes related to prior-year hurricanes. These were partly offset by lower natural gas sales volumes and higher hurricane-related costs in 2005 of $5 million ($7.6 million in 2005 compared to $2.6 million in 2004). Production expense decreased due to the sale of oil and gas properties in the Gulf of Mexico in June 2005, partially offset by costs associated with higher deepwater production volumes. Depreciation expense increased mostly due to the higher crude oil sales volumes. Natural gas sales volumes decreased in the most recent quarter primarily due to production lost during downtime subsequent to Hurricanes Katrina and Rita and lower production from fields in the Gulf of Mexico that were sold in 2005.

Continuing operations in Canada earned $98.2 million this quarter compared to $52.8 million a year ago. This increase was the result of higher crude oil and natural gas sales prices, higher crude oil sales volumes and lower dry hole costs offshore Eastern Canada. Production and depreciation expenses increased due to more crude oil sales volumes for higher-cost heavy oil. Additionally, production expense for the Company’s synthetic oil operation increased due to higher repair, natural gas purchased and employee compensation costs. Heavy oil prices did not increase in proportion to lighter oil prices in the 2005 period compared to 2004 due to a wider price differential between light and heavy oil in the 2005 period and the effect of price hedges on a portion of heavy oil production.

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

U.K. operations earned $15.2 million in the current quarter, down from $42.8 million in the prior year. The decrease was primarily due to an after-tax gain of $24.6 million in the 2004 period from sale of the “T” Block field in the U.K. North Sea and lower oil sales volumes following the 2004 sale partially offset by higher crude oil sales prices in the 2005 period. Production expenses were virtually unchanged in the current period due to planned workovers and depreciation expense declined in the most recent quarter due to lower sales volumes. Dry hole costs increased in the 2005 period due to an unsuccessful offshore well on License P011.

Operations in Ecuador earned $13.3 million in the third quarter of 2005 compared to a loss of $.1 million a year ago. The improvement was due to higher sales volumes in the 2005 period. Virtually no sales occurred in Ecuador in the 2004 third quarter while the Company was in the process of realigning its transportation and marketing arrangements. The Company has thus far achieved no settlement with the other owners related to the Company’s entitlement of approximately 1.5 million barrels that were withheld by the operator in 2004 during a dispute over Murphy’s new transportation and marketing arrangement. Settlement negotiations are ongoing.

Operations in Malaysia reported earnings of $10.6 million in the 2005 period compared to a loss of $7 million during the same period in 2004. The increase in Malaysia was primarily due to lower dry hole costs and increased oil sales prices and volumes in the current period, partially offset by higher geological and geophysical costs in the 2005 period.

Other international operations reported a loss of $4 million in the third quarter of 2005 compared to a loss of $2.9 million in the comparable period a year ago. Exploration expenses in the Republic of Congo and higher selling and general expenses were the primary causes of the higher loss in the 2005 period.

On a worldwide basis, the Company’s crude oil and condensate prices averaged $53.15 per barrel in the current quarter compared to $40.12 in the third quarter of 2004. Average crude oil and liquids production from continuing operations was 94,151 barrels per day in the third quarter of 2005 compared to 88,445 barrels per day in the second quarter of 2004, with the net increase primarily attributable to production at the Front Runner field in the deepwater Gulf of Mexico, which commenced production in the fourth quarter of 2004, and higher heavy oil production at the Seal area in Western Canada. Oil production in the United Kingdom and offshore Eastern Canada was lower in the 2005 period due to downtime for maintenance. Hurricanes Katrina and Rita and tropical storms reduced U.S. production by approximately 11,800 barrels of oil per day and 21 million cubic feet of natural gas per day in the 2005 third quarter, while Hurricane Ivan and other tropical storms reduced U.S. production by about 3,600 barrels of oil per day and eight million cubic feet of natural gas per day in the third quarter 2004. Crude oil sales volumes from continuing operations averaged 93,910 barrels per day in the third quarter 2005 compared to 81,927 barrels per day in the 2004 period. Virtually no sales occurred in Ecuador in the 2004 third quarter while the Company was in the process of realigning its transportation and marketing arrangements. While sales have resumed in Ecuador in 2005, the Company continues to pursue settlement of its under sold position from the 2004 period with the other owners in Block 16. North American natural gas sales prices averaged $8.54 per thousand cubic feet (MCF) in the most recent quarter compared to $6.00 per MCF in the same quarter of 2004. Natural gas sales volumes from continuing operations averaged 70 million cubic feet a day in the third quarter 2005, down 29 million cubic feet per day from the 2004 quarter. The decline in natural gas sales volumes was primarily due to the sale of properties on the continental shelf in the Gulf of Mexico in the second quarter 2005, and more natural gas production lost from hurricanes in the Gulf of Mexico in the third quarter 2005 compared to the 2004 period.

Operations in the United States for the nine months ended September 30, 2005 produced income of $321.1 million compared to income of $117.2 million in 2004. The improvement was primarily due to a $106.8 million after-tax gain on sale of oil and gas properties in the Gulf of Mexico, higher oil and natural gas sales prices, higher oil sales volumes due to the start-up of the Front Runner field in the deepwater Gulf of Mexico in the fourth quarter of 2004 and after-tax business interruption insurance recoveries of $7 million. The 2004 period included $15.4 million of after-tax gains on disposal of several minor onshore natural gas properties. Production expense increased due to higher oil sales volume and higher workover costs. After-tax costs associated with hurricanes were $5 million higher in the 2005 period compared to 2004. Depreciation expense increased due to the higher crude oil sales volumes. Natural gas sales volumes declined due to lower sales volumes from Gulf of Mexico fields sold in June 2005 and production lost during downtime following Hurricanes Katrina and Rita.

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

In the first nine months of 2005, Canadian continuing operations earned $232.2 million compared to $170.9 million a year ago. Higher sales prices for oil and natural gas and lower exploration expenses offshore Eastern Canada were partially offset by lower natural gas sales volumes. Canadian heavy oil prices realized did not increase in 2005 in proportion to lighter oil prices due to a wider differential between light and heavy oil prices and the effect of price hedges covering a portion of heavy oil production. Production and depreciation expenses increased due to more crude oil sales volumes for higher-cost heavy oil. Additionally, production expenses for synthetic oil operations increased in the current period primarily due to higher repair, natural gas purchased and employee compensation costs.

The Company sold most of its conventional oil and gas assets in Western Canada in the second quarter of 2004 for cash proceeds of $583 million, which generated an after-tax gain included in discontinued operations of $169.2 million. The operating results of these sold assets have also been reported as discontinued operations for all periods presented.

Income in the U.K. for the nine-month period ended September 30, 2005 was $52.9 million compared to $72.4 million a year ago. The decrease was primarily due to an after-tax gain of $24.6 million in the 2004 period from sale of the “T” Block field in the U.K. North Sea and lower oil sales volumes following the 2004 sale partially offset by higher crude oil sales prices in the 2005 period. Production expenses and depreciation expense decreased due to the lower sales volumes. Dry hole costs increased in the 2005 period due to an unsuccessful well offshore on License P011.

For the first nine months of 2005, earnings in Ecuador were $25.8 million compared to $6.6 million for the 2004 period. Higher crude oil sales prices and volumes in the 2005 period were partially offset by higher depreciation expense. Production expenses were only slightly higher in the 2005 period despite the higher sales volumes due to the Company’s new transportation and marketing arrangements effective in the second half of 2004 and there being virtually no sales in the third quarter of 2004 while the Company was in the process of realigning its transportation and marketing arrangements.

Malaysia operations earned $22.5 million in the 2005 period compared to a loss of $.4 million a year ago. The improvement in 2005 earnings was primarily due to higher crude oil sales volumes and prices. Production expense and depreciation expense increased in the 2005 period due to the higher crude oil sales volumes. Higher spending on 3-D seismic more than offset lower dry hole costs.

Other international operations reported a loss of $35.1 million in the first nine months of 2005 compared to a loss of $7.1 million in the 2004 period. The higher loss was primarily due to expensing two dry holes and incurring increased other exploration costs in the Republic of Congo in the 2005 period.

For the nine-month period ended September 30, 2005, the Company’s sales price for crude oil and condensate averaged $45.15 per barrel compared to $34.84 per barrel in 2004. Crude oil and condensate production from continuing operations in 2005 averaged 104,588 barrels per day compared to 93,632 barrels per day a year ago. The higher production in 2005 was primarily attributable to start-up of the Front Runner field in late 2004. Oil production also increased in Malaysia and the heavy oil area in Canada but declined in the U.K. following sale of the “T” Block field in 2004. The average sales price for North American natural gas in the first nine months of 2005 was $7.37 per MCF, up from $6.04 in 2004. Natural gas sales volumes from continuing operations were down from 115 million cubic feet per day in 2004 to 96 million cubic feet per day in 2005, with the decline due to lower sales volumes from Gulf of Mexico fields sold in June 2005 and production downtime following Hurricanes Katrina and Rita.

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

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

Selected operating statistics for the three-month and nine-month periods ended September 30, 2005 and 2004 follow.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005	2004
Net crude oil, condensate and gas liquids produced –barrels per day		94,151	88,428		104,588	97,713
Continuing operations		94,151	88,445		104,588	93,632
United States		22,352	17,063		29,229	19,657
Canada
– light		532	601		566	671
– heavy		10,343	4,663		10,876	4,567
– offshore		20,640	23,390		23,544	26,715
– synthetic		11,782	12,048		10,394	11,976
United Kingdom		6,704	10,784		8,346	11,560
Malaysia		13,683	12,088		13,863	10,705
Ecuador		8,115	7,808		7,770	7,781
Discontinued operations		—	(17	)	—	4,081

Net crude oil, condensate and gas liquids sold –barrels per day		93,910	81,910		105,723	96,019
Continuing operations		93,910	81,927		105,723	91,938
United States		22,352	17,063		29,229	19,657
Canada
– light		532	601		566	671
– heavy		10,343	4,663		10,876	4,567
– offshore		21,359	24,313		23,414	27,816
– synthetic		11,782	12,048		10,394	11,976
United Kingdom		6,967	10,475		8,510	11,667
Malaysia		13,415	12,617		15,071	11,082
Ecuador		7,160	147		7,663	4,502
Discontinued operations		—	(17	)	—	4,081

Net natural gas sold – thousands of cubic feet per day		69,544	98,858		96,160	157,172
Continuing operations		69,544	98,919		96,160	115,307
United States		57,190	81,531		78,947	94,525
Canada		9,351	13,424		10,591	14,205
United Kingdom		3,003	3,964		6,622	6,577
Discontinued operations		—	(61	)	—	41,865

Total net hydrocarbons produced – equivalent barrels per day (1)		105,742	104,904		120,615	123,908
Total net hydrocarbons sold – equivalent barrels per day (1)		105,501	98,386		121,750	122,214
Total net hydrocarbons produced from continuing operations – equivalent barrels per day (1)		105,742	104,932		120,615	112,850
Total net hydrocarbons sold from continuing operations – equivalent barrels per day (1)		105,501	98,414		121,750	111,156

Weighted average sales prices
Crude oil and condensate – dollars per barrel (2)
United States	$	55.38	37.70		46.56	34.21
Canada (3)
– light		56.15	40.49		50.75	36.02
– heavy (4)		29.78	23.25		20.47	20.07
– offshore		59.33	40.16		50.45	35.30
– synthetic		63.99	41.83		57.42	37.99
United Kingdom		61.27	42.52		51.66	35.98
Malaysia (5)		47.65	45.99		44.96	40.36
Ecuador		45.99	30.51		35.06	24.73

Natural gas – dollars per thousand cubic feet
United States (2)	$	8.65	6.17		7.46	6.16
Canada (3)		7.87	4.98		6.68	5.24
United Kingdom (3)		4.47	3.73		4.93	4.13

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

(2)	Includes intracompany transfers at market prices.

(3)	U.S. dollar equivalent.

(4)	Includes the effects of the Company’s 2005 hedging program.

(5)	Prices in 2005 are net of a payment under the terms of the production sharing contract for Block SK 309.

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

Continuing Oil and Gas Operating Results


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

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

Total exploration expenses		7.5		3.4		3.9	—		16.4		1.7		—	32.9

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

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

Three Months Ended September 30, 2004
Oil and gas sales and other revenues	$	104.4		107.8		81.0	.4		53.4		.9		46.3	394.2
Production expenses		17.7		9.0		4.1	.3		7.1		—		17.9	56.1
Net costs associated with hurricanes		2.6		—		—	—		—		—		—	2.6
Depreciation, depletion and amortization		15.0		23.3		6.4	.1		8.2		.1		2.7	55.8
Accretion of asset retirement obligations		.9		.8		.6	—		—		.1		.1	2.5
Exploration expenses
Dry holes		7.6		23.2		—	—		19.0		—		—	49.8
Geological and geophysical		1.8		.5		—	—		12.1		.5		—	14.9
Other		.8		.1		.1	—		.1		.3		—	1.4

		10.2		23.8		.1	—		31.2		.8		—	66.1
Undeveloped lease amortization		3.0		.7		—	—		—		.4		—	4.1

Total exploration expenses		13.2		24.5		.1	—		31.2		1.2		—	70.2

Selling and general expenses		4.1		2.3		.9	.2		1.1		2.2		.2	11.0
Income tax provisions (benefits)		17.9		12.2		26.1	(.1	)	12.8		.2		8.3	77.4

Results of operations (excluding corporate overhead and interest)	$	33.0		35.7		42.8	(.1	)	(7.0	)	(2.9	)	17.1	118.6

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

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

Total exploration expenses		50.1		6.1		4.1	—		54.4		28.5		—	143.2

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

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

Nine Months Ended September 30, 2004
Oil and gas sales and other revenues	$	367.4		320.5		161.1	30.5		122.9		2.5		124.6	1,129.5
Production expenses		56.6		27.2		15.8	13.8		18.2		—		55.4	187.0
Net costs associated with hurricanes		2.6		—		—	—		—		—		—	2.6
Depreciation, depletion and amortization		51.0		72.6		21.9	5.2		21.6		.1		8.0	180.4
Accretion of asset retirement obligations		2.7		2.1		2.0	—		.1		.3		.3	7.5
Exploration expenses
Dry holes		40.7		23.1		—	—		36.5		.1		—	100.4
Geological and geophysical		5.7		1.7		—	—		15.1		1.2		—	23.7
Other		4.0		1.7		.4	—		.1		.5		—	6.7

		50.4		26.5		.4	—		51.7		1.8		—	130.8
Undeveloped lease amortization		9.4		1.9		—	—		—		.4		—	11.7

Total exploration expenses		59.8		28.4		.4	—		51.7		2.2		—	142.5

Selling and general expenses		14.2		8.0		2.4	.5		3.5		6.5		.5	35.6
Income tax provisions		63.3		54.1		46.2	4.4		28.2		.5		17.6	214.3

Results of operations (excluding corporate overhead and interest)	$	117.2		128.1		72.4	6.6		(.4	)	(7.1	)	42.8	359.6

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

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

Results of Operations (Contd.)

Refining and Marketing

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


	Income
	Three Months Ended September 30,			Nine Months Ended September 30,
(Millions of dollars)	2005		2004	2005	2004
Refining and marketing
North America	$	11.2	12.9	62.6	29.8
United Kingdom		20.8	5.8	31.3	22.0

Total	$	32.0	18.7	93.9	51.8

The Company’s refining and marketing operations generated a profit of $32 million in the third quarter 2005 compared to a profit of $18.7 million in the 2004 quarter. The earnings improved due to higher profits in the U.K in the 2005 period, partially offset by lower profits in North America. Murphy’s downstream business incurred after-tax costs related to hurricanes of $13.9 million in the just completed quarter ($22.1 million before income taxes). The Company’s Meraux, Louisiana, refinery experienced flooding during Hurricane Katrina and was shut down for the last 34 days of the quarter. Worldwide petroleum product sales averaged 363,284 barrels per day in 2005, compared to 353,538 barrels per day in the same period in 2004. Worldwide refinery inputs were 145,315 barrels per day in the third quarter of 2005 compared to 173,677 in the 2004 quarter; inputs in 2005 were adversely affected by the shut down at the Meraux refinery caused by Hurricane Katrina. The U.K. operations had a $2.2 million after-tax benefit in the 2005 quarter from refunds of a portion of prior-year property taxes at the Milford Haven, Wales refinery.

The Company’s refining and marketing operations generated a profit of $93.9 million in the first nine months of 2005 compared to a profit of $51.8 million in 2004. The improved current year result was based on better margins in both the North American and U.K. businesses in 2005. The 2005 results included net-of-tax hurricane related costs of $13.9 million. The Meraux refinery was shut down for all of September 2005 due to damages caused by Hurricane Katrina.

Selected operating statistics for the three-month and nine-month periods ended September 30, 2005 and 2004 follow.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2005	2004	2005	2004
Refinery inputs – barrels per day	145,315	173,677	167,809	175,469
North America	105,454	138,483	135,325	138,816
United Kingdom	39,861	35,194	32,484	36,653

Petroleum products sold – barrels per day	363,284	353,538	358,247	334,477
North America	322,860	317,835	323,790	297,697
Gasoline	243,352	210,707	226,565	204,324
Kerosine	2,329	721	6,269	3,193
Diesel and home heating oils	48,947	78,098	62,697	67,547
Residuals	13,800	13,953	19,023	13,180
Asphalt, LPG and other	14,432	14,356	9,236	9,453
United Kingdom	40,424	35,703	34,457	36,780
Gasoline	14,004	9,711	11,552	11,730
Kerosine	2,506	2,349	2,228	2,477
Diesel and home heating oils	18,227	14,366	15,576	14,456
Residuals	3,545	3,441	3,013	4,098
LPG and other	2,142	5,836	2,088	4,019

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

Results of Operations (Contd.)

Corporate and other

Net corporate costs, after income taxes, were $14.2 million in the 2005 third quarter compared to costs of $21.5 million in the 2004 quarter. The 2005 period included after-tax costs for foreign exchange of $2.7 million, while the 2004 period included costs of $8.2 million for foreign exchange. In addition, the Company incurred less net interest expense due to lower average debt and a higher portion of interest costs being capitalized in the 2005 period. Partially offsetting these favorable variances in 2005 were higher administrative expenses that primarily related to employee compensation.

Corporate after-tax costs were $30.0 million in the first nine months of 2005 compared to $46.8 million in the 2004 period. The Company had lower net interest expense in the 2005 period due to a combination of lower average debt levels and higher interest capitalized on development projects. The 2005 period included after-tax foreign exchange charges of $2.4 million, while 2004 included after-tax foreign exchange charges of $7.8 million. Higher administrative expenses in 2005, primarily related to employee compensation costs, partially offset lower interest and foreign exchange expenses.

Financial Condition

Net cash provided by continuing operating activities was $761.2 million for the first nine months of 2005 compared to $809.8 million for the same period in 2004. The decline in 2005 was primarily attributable to changes in other operating working capital other than cash and cash equivalents between 2005 and 2004. Changes in operating working capital other than cash and cash equivalents used cash of $150.9 million in the first nine months of 2005 and provided cash of $59.1 million in the first nine months of 2004. This use of working capital in 2005 was primarily caused by an increase in accounts receivable and inventories and a decrease in income taxes payable that was partially offset by an increase in accounts payable. Cash from operating activities was reduced by expenditures for major repairs and asset retirement obligations totaling $30.2 million in the first nine months of 2005 and $14.7 million in 2004, with the increase in 2005 mostly attributable to a full plant-wide turnaround at the Milford Haven, Wales refinery. Proceeds from the sale of assets, excluding discontinued operations, provided cash of $173.6 million in the first nine months of 2005 compared to $59.5 million in the same period in 2004.

Other predominant uses of cash in each period were for dividends, which totaled $62.3 million in 2005 and $57.5 million in 2004 and for capital expenditures, which including amounts expensed, are summarized in the following table.


	Nine Months Ended September 30,
(Millions of dollars)	2005			2004
Capital Expenditures – continuing operations
Exploration and production	$	765.2		653.7
Refining and marketing		163.3		106.8
Corporate and other		14.3		1.1

Total capital expenditures – continuing operations		942.8		761.6
Geological, geophysical and other exploration expenses charged to income		(61.7	)	(30.4	)

Total property additions and dry holes – continuing operations	$	881.1		731.2

Working capital (total current assets less total current liabilities) at September 30, 2005 was $582.5 million, up $158.1 million from December 31, 2004. This level of working capital includes carrying certain inventories using lower historical costs under LIFO accounting. The carrying value of these inventories were $361 million and $219 million below current costs at September 30, 2005 and December 31, 2004, respectively.

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

Financial Condition (Contd.)

At September 30, 2005, long-term notes payable of $597.9 million was virtually unchanged from December 31, 2004. Long-term nonrecourse debt of a subsidiary was $11.6 million, down $4 million from December 31, 2004, primarily due to repayments. A summary of capital employed at September 30, 2005 and December 31, 2004 follows.


(Millions of dollars)	September 30, 2005			Dec. 31, 2004
(Millions of dollars)	Amount		%	Amount		%
Capital Employed
Notes payable	$	597.9	15.2	$	597.7	18.3
Nonrecourse debt of a subsidiary		11.6	.3		15.6	.5
Stockholders’ equity		3,311.9	84.5		2,649.2	81.2

Total capital employed	$	3,921.4	100.0	$	3,262.5	100.0

On June 14, 2005, Murphy entered into a five year $1 billion committed credit facility, whereby the Company and certain wholly-owned subsidiaries may borrow funds from a major banking consortium. The new credit facility replaces two similar committed credit facilities with an aggregate borrowing capacity of $700 million. Borrowings under the new credit facility bear interest at prime or varying cost of fund options. Facility fees are due on the commitments. No amounts had been borrowed under this credit facility as of September 30, 2005.

Accounting and Other Matters

In October 2004, the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (the “Act”) became law. The FASB issued FSP 109-1 in December 2004 to provide guidance on the application of SFAS No. 109, Accounting for Income Taxes, to the provision within the Act that will ultimately provide a tax deduction of up to 9% on qualified production activities. The tax deduction phases in at 3% beginning in 2005 and reaches 9% in 2010. FSP 109-1 concluded that the deduction should be accounted for as a special deduction in accordance with SFAS 109, whereby the tax benefit is recognized as realized, rather than as a one-time benefit due to a reduction of deferred tax liabilities. This FSP was effective upon issuance. The Company recorded a tax benefit of approximately $3.1 million in the nine-month period ended September 30, 2005 related to the Act.

SFAS No. 151, Inventory Costs, was issued by the FASB in November 2004. This statement amends Accounting Research Bulletin No. 43, to clarify that abnormal amounts of idle facility expense, freight, handling costs, and wasted materials should be recognized as current-period charges, and it also requires that allocation of fixed production overheads be based on the normal capacity of the related production facilities. The provisions of this statement will be effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The provisions of this statement will be applied prospectively. The Company does not expect the adoption of this statement to have a significant impact on its results of operations.

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

Accounting and Other Matters (Contd.)

In March 2005 the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS No. 143. This interpretation clarifies the term conditional asset retirement obligation as used in SFAS No. 143 and when a company would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. This interpretation is effective for fiscal years ending after December 15, 2005. The Company is currently evaluating whether the adoption of this interpretation will have any effect on its financial statements.

In March 2005, the EITF decided in Issue 04-6, Accounting for Stripping Costs Incurred during Production in the Mining Industry, that mining operations should account for post-production stripping costs as a variable production cost that should be considered a component of mineral inventory costs. The Company’s synthetic oil operations at Syncrude may be affected by this ruling. The EITF consensus is effective for fiscal years beginning after December 15, 2005 and any adjustment required as of the January 1, 2006 effective application date for the Company will be recorded as a cumulative effect of a change in accounting principle. The Company is currently evaluating the accounting implications of this new EITF consensus.

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

Murphy holds a 20% interest in Block 16 Ecuador, where the Company and its partners produce oil for export. In 2001, the local tax authorities announced that Value Added Taxes (VAT) paid on goods and services related to Block 16 and many oil fields held by other companies will no longer be reimbursed. In response to this announcement, oil producers have filed actions in the Ecuador Tax Court seeking determination that the VAT in question is reimbursable. In July 2004, international arbitrators ruled that VAT was recoverable by another oil company, but the State of Ecuador responded that it was not bound by this arbitral decision. As of September 30, 2005, the Company has a receivable of approximately $14.3 million related to VAT. Murphy believes that its claim for reimbursement of VAT under applicable Ecuador tax law is valid, and it does not expect that the resolution of this matter will have a material adverse affect on the Company’s net income, financial condition or liquidity in future periods.

Environmental matters and class action lawsuits associated with a crude oil spill at the Company’s Meraux, Louisiana, refinery are addressed in Note J to the Consolidated Financial Statements beginning on page 12 of this Form 10-Q.

Outlook

Crude oil and natural gas prices remain strong in October 2005, but these prices have retreated from the highs experienced in the third quarter 2005. The Company’s Meraux, Louisiana refinery is expected to be shut down through approximately April 1, 2006 to repair damages caused by flooding following Hurricane Katrina. The Company expects its oil and natural gas production in the fourth quarter of 2005 to average 101,000 barrels of oil equivalent per day, down from 105,742 barrels of oil equivalent per day in the third quarter of 2005. The anticipated decline is mostly due to projected lost production in the United States of 23,000 barrels of oil equivalent per day while hurricane repairs to third party infrastructure are completed in the Gulf of Mexico. Production in the third quarter 2005 was unfavorably affected by approximately 15,300 barrels of oil equivalent per day due to downtime for hurricanes and subsequent repairs of company and third party facilities. The Company expects that all Gulf of Mexico fields idled for hurricane repairs will be back on production by the end of 2005. Total Company production in 2006 is anticipated to average 120,000 barrels of oil equivalent per day. The Company currently anticipates total capital expenditures in 2005 of approximately $1.3 billion.

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

Forward-Looking Statements

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Murphy was a party to natural gas price swap agreements at September 30, 2005 for a remaining notional volume of 1.1 million MMBTU that are intended to hedge the financial exposure of its Meraux, Louisiana refinery to fluctuations in the future price of a portion of natural gas to be purchased for fuel in 2005 and 2006. In each month of settlement, the swaps require Murphy to pay an average natural gas price of $3.35 per MMBTU and to receive the average NYMEX price for the final three trading days of the month. At September 30, 2005, the estimated fair value of these agreements was recorded as an asset of $9.7 million. A 10% increase in the average NYMEX price of natural gas would have increased this asset by $1.3 million, while a 10% decrease would have reduced the asset by a similar amount.

At September 30, 2005, the Company was a party to forward sale contracts covering 2,000 barrels per day in blended heavy oil sales during 2005 and 4,000 barrels per day in 2006. The contracts are intended to hedge the financial exposure of the Company’s blended heavy oil sales in Canada during the respective contract period and are priced at $29.00 per barrel in 2005 and $25.23 per barrel in 2006. At September 30, 2005, the estimated fair value of these agreements was recorded as a $34.2 million liability. A 10% increase in the price of Canadian heavy oil at the Hardisty terminal in Canada would have increased this liability by $7.6 million, while a 10% decrease would have decreased this liability by a similar amount.

ITEM 4. CONTROLS AND PROCEDURES

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

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

There were no significant changes in the Company’s internal controls over financial reporting that occurred during the nine-month period ended September 30, 2005 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 flooding damage to a crude oil storage tank following Hurricane Katrina. Since then additional class action lawsuits have been filed in the same court against Murphy Oil USA, Inc. and/or Murphy Oil Corporation also seeking unspecified damages related to the crude oil release. The suits have been consolidated into a single action in the U.S. District Court for the Eastern District of Louisiana. The Company believes that insurance coverage exists for this release and it does not expect to incur significant costs associated with the class action lawsuits. Accordingly, the Company believes that the ultimate resolution of these class action lawsuits will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

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

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)	The Exhibit Index on page 31 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 September 9, 2005 announcing that two class action lawsuits had been filed against the Company and one of its subsidiaries seeking unspecified damages caused by a release of crude oil at its Meraux, Louisiana refinery.

(c)	A report on Form 8-K was filed on July 26, 2005 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, 2005.

(d)	A report on Form 8-K was filed on July 6, 2005 that included a News Release announcing the Company’s expected results of operations for the three-month and six-month periods ended June 30, 2005.

SIGNATURE

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


*MURPHY OIL CORPORATION*
(Registrant)

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

November 7, 2005

(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.

Computation of Ratio of Earnings to Fixed Charges

EXHIBIT 12.1

Murphy Oil Corporation and Consolidated Subsidiaries

Computation of Ratio of Earnings to Fixed Charges (unaudited)

(Thousands of dollars)


	Nine Months Ended Sept. 30, 2005			Years Ended December 31,
	Nine Months Ended Sept. 30, 2005			2004		2003		2002		2001		2000
Income from continuing operations before income taxes	$	1,119,146		804,936		374,205		121,566		438,972		407,813
Distributions less than equity in earnings of affiliates		(5,646	)	(4,225	)	(209	)	(3	)	(365	)	(34	)
Previously capitalized interest charged to earnings during period		12,442		14,065		10,457		7,748		3,450		3,507
Interest and expense on indebtedness, excluding capitalized interest		8,619		34,064		20,511		26,968		19,006		16,337
Interest portion of rentals*		6,879		7,908		9,857		9,445		7,953		5,808

Earnings before provision for taxes and fixed charges	$	1,141,440		856,748		414,821		165,724		469,016		433,431

Interest and expense on indebtedness, excluding capitalized interest		8,619		34,064		20,511		26,968		19,006		16,337
Capitalized interest		27,156		22,160		37,240		24,536		20,283		13,599
Interest portion of rentals*		6,879		7,908		9,857		9,445		7,953		5,808

Total fixed charges	$	42,654		64,132		67,608		60,949		47,242		35,744

Ratio of earnings to fixed charges		26.8		13.4		6.1		2.7		9.9		12.1

*	Calculated as one-third of rentals. Considered a reasonable approximation of interest factor.

Ex. 12-1

Section 302 CEO Certification

EXHIBIT 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Claiborne P. Deming, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Murphy Oil Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal controls over financial reporting; and

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date: November 7, 2005

/s/ Claiborne P. Deming

Claiborne P. Deming

Principal Executive Officer

Ex. 31-1

Section 302 CFO Certification

EXHIBIT 31.2

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Steven A. Cossé, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Murphy Oil Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date: November 7, 2005

/s/ Steven A. Cossé

Steven A. Cossé

Principal Financial Officer

Ex. 31-2

Section 906 CEO and CFO Certification

EXHIBIT 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Murphy Oil Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2005 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we, Claiborne P. Deming and Steven A. Cossé, Principal Executive Officer and Principal Financial Officer, respectively, of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to our knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

November 7, 2005

/s/ Claiborne P. Deming

Claiborne P. Deming

Principal Executive Officer

/s/ Steven A. Cossé

Steven A. Cossé

Principal Financial Officer

Ex. 32-1

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