200 Peach Street (71730) P O Box 7000 El Dorado, AR 71731-7000 (870) 862-6411 FAX (870) 864-6371
	April 30, 2010

Securities and Exchange Commission

Mr. H. Roger Schwall, Assistant Director

Division of Corporation Finance

100 F Street, NE – Mail Stop 4628

Washington, D.C. 20549-4628

Re: Murphy Oil Corporation

Form 10-K for the Fiscal Year Ended December 31, 2009

Filed February 26, 2010

File No. 001-08590

Dear Mr. Schwall:

This letter is Murphy Oil Corporation’s response to your staff comment letter dated April 2, 2010. For ease of review, the staff comments from that letter are included below in bold text, which are then followed by our response.

Form 10-K for the Fiscal Year Ended December 31, 2009

Item 6. Selected Financial Data, page 17

1. We note your presentation of percentage return on average stockholders’ equity, average borrowed and invested capital, and average total assets. We also note your presentation of long-term debt – percent of capital employed. Supplementally, explain to us how you considered providing the following:

• A clear explanation of how the measures were calculated, including reconciliation or reference to relevant amounts from your financial statements;

• A statement disclosing the reasons why you believe that presentation of the financial measure provides useful information to investors;

• To the extent material, a statement disclosing the additional purposes, if any, for which you use the measures; and,

• A cautionary statement indicating that the measures you present may be calculated differently than similarly titled measures presented by other companies.

Securities and Exchange Commission

Mr. H. Roger Schwall, Assistant Director

April 30, 2010

Page 2

Regulation S-K §229.301 permits registrants to include additional items (beyond the items specified) which the registrant believes would enhance an understanding of and would highlight other trends in their financial condition and results of operations. For many years, our Company management has used certain measures for managing our business which include percentage return on average stockholders’ equity, percentage return on average borrowed and invested capital, and percentage return on average total assets. Additionally, we measure our long-term debt leverage using long-term debt as a percentage of total capital employed. We have consistently disclosed these amounts for many years because we believe our shareholders and other interested parties find such measures helpful in understanding trends and results of the Company and as a comparison of Murphy Oil to other companies in our and other industries.

Specifically, these measures were computed as follows for the year ended December 31, 2009 (or as of December 31, 2009, as applicable).

• Percentage return on average stockholders’ equity – net income for 2009 (as per the consolidated statement of income) divided by a 12-month average for January to December 2009 of total stockholders’ equity.

• Percentage return on average borrowed and invested capital – the sum of net income for 2009 (as per the consolidated statement of income) plus after-tax interest expense for 2009 divided by a 12-month average for January to December 2009 of the sum of total long-term debt plus total stockholders’ equity.

• Percentage return on average total assets – net income for 2009 (as per the consolidated statement of income) divided by a 12-month average for January to December 2009 of total consolidated assets.

• Long-term debt–percent of capital employed – total long-term debt at that date (as per the consolidated balance sheet) divided by the sum of total long-term debt plus total stockholders’ equity at that date (as per the consolidated balance sheet).

Other than for management purposes, there are no other material uses for which these measures are used. In future filings, we agree to provide a cautionary statement in Item 6 that indicates that these measures may be calculated differently than similarly titled measures that may be presented by other companies.

Securities and Exchange Commission

Mr. H. Roger Schwall, Assistant Director

April 30, 2010

Page 3

2. We note your presentation of capital expenditures. Explain to us how you considered providing a reconciliation to corresponding amounts presented in your statements of cash flows.

The total capital expenditures included in the Selected Financial Data are presented on an accrual basis, whereas the total capital expenditures included in the statement of cash flows are included on a cash basis. Due to the timing of payments for capital expenditures, total cash required for capital expenditures reported in the statement of cash flows can be more or less than capital expenditures as presented on an accrual basis in Selected Financial Data. The Company agrees to explain in future filings that the capital expenditures as presented in Selected Financial Data differ from capital expenditures in the statement of cash flows due to the timing for cash payments associated with these capital expenditures.

Item 7. MD&A of Financial Condition and Results of Operations

Results of Operations, page 18

3. Explain to us in more detail, the year-to-year variation in “Interest and Other Income.” For example, you indicate that such income was higher in 2009 due to “a combination of more favorable income effects from transactions denominated in foreign currencies” while in 2008 it was lower due to greater losses on foreign currency exchange…mostly attributable to a stronger U.S. dollar compared to the British pound sterling.” Explain to in more detail why there was such a significant swing due to foreign currencies. Also, explain in more detail the anticipated recovery of federal royalties and whether this is a one-time occurrence.

Regarding the annual variations in net income related to transactions denominated in foreign currencies, the Company is primarily affected by variances in the exchange rates of the U.S. dollar (reporting currency) against two foreign currencies – the British pound sterling (functional currency of the Company’s U.K. downstream operating subsidiary) and the Malaysian ringgit (local currency of the Company’s Malaysian exploration and production (E&P) subsidiaries). The Company is also affected, but less significantly in recent periods, by variances in exchange rates for the U.S. dollar and the Canadian dollar and Euro.

The Company’s U.K. downstream business has significant intercompany loans payable denominated in U.S. dollars, which primarily arose to finance the acquisition of the Milford Haven, Wales refinery in December 2007. During 2009, the sterling strengthened by more than 11% against the U.S. dollar, which effectively generated financial foreign exchange gains in the U.K. operations as the loans were payable with fewer pounds sterling. The intercompany loans receivable are held by U.S. dollar functional affiliates of the U.K. subsidiary, and therefore, do not have corresponding offsetting foreign exchange impacts. During 2008, the exchange rate for the pound sterling declined by more than 27% versus the U.S. dollar, which effectively led to a foreign exchange loss for the U.K. downstream operations related to these intercompany loans.

Securities and Exchange Commission

Mr. H. Roger Schwall, Assistant Director

April 30, 2010

Page 4

The Malaysian E&P subsidiaries are U.S. dollar functional companies which pay significant income taxes in the ringgit local currency. Because of the level of income generated in Malaysia and the timing of required tax payments, a significant amount of current tax liabilities can be outstanding for many months. Additionally, noncurrent deferred tax liabilities are significant for this operation, mostly due to accelerated tax depreciation. The Malaysian ringgit conversion rate did not move significantly versus the U.S. dollar during 2009. But in 2008, the ringgit fell against the dollar by about 5%, which led to a foreign exchange gain associated with less expensive current and deferred income taxes owed in this local currency (by the U.S. dollar functional subsidiaries). Essentially over the last several years, the U.S. dollar exchange rates have been quite volatile for the primary foreign currencies that affect the Company’s operations. Additionally, these exchange rates often are quite volatile on a quarter-to-quarter basis.

The significant recovery of federal royalties will be a one-time event. However, beginning in late 2009 and thenceforth, the Company will no longer accrue or pay federal royalties on these affected properties in the Gulf of Mexico. The impact will be much less significant for future individual reporting periods. The lack of federal royalties payable could be affected in future periods by the enactment of laws by the U.S. Congress. The royalty refund was received from the MMS in late February 2010. Interest income owed by the MMS for this royalty remain collectible at the date of this letter.

Exploration and Production, page 21

4. You indicate that earnings in 2009 were lower than in 2008 “primarily due to significantly lower realized sales prices for [your] crude oil production.” You also cite lower natural gas prices in North America, higher production and depreciation expenses and other factors. You also indicate that you “benefited from higher oil and natural gas sales volumes and lower exploration expense.” To the extent practicable quantify the impact of each of these factors. For instance, quantify the impact of changes in sales prices versus changes in volumes. Provide comparable disclosure for the prior years’ discussions as well.

Changes in the realized price of oil was the primary factor affecting the Company’s E&P earnings in 2009 and 2008 compared to the prior year. On page 24 of the 2009 Form 10-K, the Company provides the sensitivity of E&P earnings to a $1.00 per barrel change in oil price. Based on this sensitivity for oil, of the approximate $911 million reduction in E&P earnings in 2009 versus 2008, lower oil sales prices accounted for approximately $936 million of the reduction. An anticipated recovery of U.S. federal royalties improved E&P earnings in 2009 by approximately $159 million, but 2008 included a benefit of approximately $108 million from sale of two assets in Canada. In 2008, E&P earnings increased by approximately $974 million compared to 2007. Of this amount, higher oil prices accounted for approximately $529 million. Gains on sale of two Canada oil and gas assets in 2008 added approximately $108 million to 2008 income. Higher crude oil sales volumes accounted for the bulk of the remaining improvement in E&P earnings in 2008 compared to 2007. The Company provides considerable other disclosures in MD&A concerning variances between year for expenses such as production, exploration and depreciation. Additionally, the income statements for E&P segments are provided in tabular form in Schedule 4 – Results of Operations for Oil and Gas Producing Activities on page F-44 and F-45 of the 2009 Form 10-K. The Company believes that its disclosures adequately address these changes. As in the past, we will evaluate for future filings whether there are further disclosures that are necessary to adequately discuss changes in operating results, cash flows and financial position between periods.

Securities and Exchange Commission

Mr. H. Roger Schwall, Assistant Director

April 30, 2010

Page 5

5. Clarify what you mean by “oil tanker liftings.”

Under the “Revenue Recognition” heading of Note A – Significant Accounting Policies in the Form 10-K for 2009, we disclose that “revenue from the sales of crude oil, natural gas and refined petroleum products are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer.” Because the timing of oil sales deliveries does not always track closely with oil production (due to changes in inventory levels), we often must discuss changes in both oil production and oil sales volumes to distinguish changes in production volume metrics and crude oil sales revenues. The reference on page 21 to “oil tanker liftings” refers to completion of the revenue cycle for several significant offshore oil fields as revenues are recorded for these oil fields when deliveries have been made and transfer of legal ownership has occurred. Deliveries usually occur when oil passes through the sales flange onto crude oil tankers hired or owned by the purchasing party. We will consider changing this terminology in future filings to timing of “sales transactions” or similar language as this terminology may be more understandable to the reader.

6. You currently blend the discussion of three years of revenues and expenses in one paragraph. Consider breaking out the discussion – either by revenues versus expenses, or by years – into separate paragraphs.

We agree in future filings to separate the discussions of E&P results and downstream results into separate paragraphs, most likely by years, in order to make the MD&A discussion easier to read.

Securities and Exchange Commission

Mr. H. Roger Schwall, Assistant Director

April 30, 2010

Page 6

Financial Statements

Note S – Terra Nova Working Interest Redetermination, page F-35

7. We note your disclosure regarding the Terra Nova working interest redetermination. Based on the disclosure, we understand that the redetermination was contemplated by, and occurred as a result of, the original terms of the joint agreement, and not as a result of a subsequent development or event. If our understanding is not correct, please clarify for us. Otherwise, describe the relevant terms of the joint agreement. Additionally, describe the facts and circumstances surrounding the timing of the redetermination. Your response should address, but not necessarily be limited to:

• When, and under what circumstances, a redetermination can be required;

• Whether there are limits on the number or timing of any additional redeterminations, and;

• Whether there is a minimum or maximum working interest that you will hold after any redetermination.

Additionally, in light of the redetermination provisions, explain to us your basis for concluding that it was appropriate to recognize revenue prior to resolution of the uncertainty regarding your working interest.

Finally, tell us whether, and to what extent, you participate in any other agreements or arrangements in which your interest is subject to subsequent redetermination or adjustment.

A one-time redetermination of working interest ownership percentages for the Terra Nova field, offshore Newfoundland, Canada, was contractually agreed to by the owners in order to allow time for the full area of this large field to be adequately explored, developed and assessed for ultimate reserve recoverability. Varying ownership interests for separate sections of the field further complicates the ultimate resolution of the redetermination. The contract called for the field operator to present the initial redetermination findings and then, if the owners could not agree, called for an arbitration process to ultimately determine the redetermined working interest percentage of each owner. The contract called for this redetermination process to occur at payout of the field (which occurred near year-end 2004). The operator completed and presented to the owners their calculation of redetermined interests in 2009. Each owner performed separate studies of the field to determine and present their view of the field for purposes of arbitrating the final redetermination. Due to the complexity of the field and amount of data to consider, the arbitration process is not expected to be completed until late 2010. The contract calls for a cash settlement upon final redetermination and until that process is complete, the Company continues to be allocated a 12% share of net oil production for sale. As disclosed in Note A – Revenue Recognition, the Company’s accounting policy is to recognize revenues from oil and gas sales based on the actual volumes sold less any cash royalties owed. Therefore, we believe it was proper accounting to recognize revenues when the Company sold oil it was allocated by the ownership consortium. The Company believes that it would have been improper accounting to provide a liability for such redetermination prior to submittal of the initial redetermined interest by the field operator, because until this was done, no probable and estimable liability existed for the Company to settle this contractual matter. The Company could not predict the result of the operator’s initial redetermination computation. The Company recorded a liability for the future settlement of the redetermination process when all owners presented their calculation for the arbitration process and all were below the Company’s current 12% level. Upon completion of the redetermination process, the Company’s working interest percentage will range from approximately 10.5% to 11.5%.

Securities and Exchange Commission

Mr. H. Roger Schwall, Assistant Director

April 30, 2010

Page 7

Excluding Terra Nova, the Company has only one other non-producing property offshore Newfoundland that requires a redetermination of working interest percentages in future periods. The redetermination process at this field is not expected to have a significant impact on the Company’s net income or financial position in future periods.

*****

In connection herewith, Murphy Oil Corporation acknowledges that:

• the company is responsible for the adequacy and accuracy of the disclosure in the filing;

• staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filings; and

• the company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

We hope this letter will satisfy your request for further information. Please direct any further inquiries to my attention.

Sincerely,

Kevin G. Fitzgerald

Senior Vice President and
Chief Financial Officer

JWE/mt

c: Paul Monsour – SEC

Brad Skinner – SEC