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Confidential Treatment Request by Marathon Oil Corporation

April 25, 2008

Chris White

Branch Chief

United States Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E., Mail Stop 7010

Washington, DC 20549

Re: Marathon Oil Corporation

Form 10-K for Fiscal Year Ended December 31, 2007

Filed February 29, 2008

File No. 1-5153

Dear Mr. White:

Set forth below are responses from Marathon Oil Corporation to comments of the staff of the United States Securities and Exchange Commission, dated March 31, 2008, concerning Marathon’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

For your convenience, we have repeated the comment prior to the response. The comment is highlighted in bold.

Form 10-K for the Fiscal Year Ended December 31, 2007

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

E&P Operating Statistics, page 46

Comment 1

Please revise your discussion in future filings to more thoroughly explain why your average realizations for natural gas in Africa were only $0.25 per thousand cubic feet in 2007 and 2005 and $0.27 in 2006, whereas they were over $5.00 per thousand cubic feet in Europe and the U.S. In addition, explain the underlying impact these average realizations are having to your results of operations as your natural gas sales from Africa increase.

Confidential Treatment Request by Marathon Oil Corporation

Response

The fixed sales price has been omitted from our response to Comment 1 pursuant to a request for confidential treatment pursuant to Rule 83 of the Freedom of Information Act. The complete text of Response 1 is being provided to the Commission in hard copy under a separate cover letter.

Almost all of our natural gas sales in Africa are generated by our production operations in Equatorial Guinea under long-term contracts with our equity method investees located there, Alba Plant LLC, Atlantic Methanol Production Company LLC and Equatorial Guinea LNG Holdings Limited. Each of these contracts calls for a fixed sales price of [redacted] per million British Thermal Units, which is approximately equivalent to [redacted] per thousand cubic feet. We will incorporate in our Form 10-K for the year ending December 31, 2008, and our Forms 10-Q for each of the quarters in the year ending December 31, 2008, an expanded description of the transactions between our production operations in Equatorial Guinea and these equity method investees,, but we are required under these contracts to keep the specific terms and conditions confidential. See Attachment A for an example of the proposed disclosure, which is based on disclosures in our 2007 Form 10-K. To expedite your review, changes have been underlined.

Financial Statements

Note 1 – Summary of Principal Accounting Policies, page F-8

Revenue Recognition, page F-9

Comment 2

Please revise future filings to disclose the amount of any crude oil or natural gas production imbalances in terms of units and value, if significant. We refer you to EITF Issue No. 90-22.

Response

Our crude oil and natural gas imbalances have not been significant. However, if these imbalances become significant, we will disclose such information in accordance with EITF Issue No. 90-22.

Comment 3

We note your disclosure, “Marathon includes royalties in its revenues and cost of revenues when settlement of the royalties is paid in cash, while royalties settled by the delivery of volumes are excluded from revenues and cost of revenues.” Please clarify the nature of these royalty payments and why you report royalties settled by the delivery of volumes in a different manner from those settled in cash.

Confidential Treatment Request by Marathon Oil Corporation

Response

When oil or natural gas is produced, the royalty owner is entitled to its royalty in either cash or in-kind volumes. The royalty percentage, cash or in-kind, is typically specified in an oil and natural gas lease.

When royalties are paid in cash, we sell the entire amount of production volumes for our own account. We retain ownership of these production volumes up to the point of sale. The royalty owner does not take ownership of any production volumes. Therefore, the entire revenue stream belongs to us. The cash payment of royalty is recorded as an expense and we recognize revenue on all volumes sold.

When royalties are paid in-kind, we take ownership of our share of the volumes produced after deduction of the royalty volumes. We then sell our net share of production. No royalty expense is recorded, and we recognize revenue only on the sale of our share of the volumes produced net of the royalty volumes. In some circumstances, we may enter into an agreement with the royalty owner to market their share of production volumes on their behalf. In this instance, we act as an agent for the royalty owner, who retains title to their share of production volumes. Again, no royalty expense is recorded, and we recognize revenue solely on the sale of our share of the volumes produced.

We believe that our accounting policy is consistent with the requirements of EITF Issue No. 99-19 and Staff Accounting Bulletin Topic 13.

Cash and cash equivalents, page F-10

Comment 4

Your accounting policies state that cash and cash equivalents include instruments “with maturities generally of three months or less.” Tell us (a) whether this includes only instruments with original maturities of three months or less; and (b) what you mean by “generally.”

Response

Our cash and cash equivalents include cash in banks and overnight bank time deposits. We will revise our accounting policy footnote in our Form 10-K for the year ending December 31, 2008, to state that cash and cash equivalents include instruments with “original maturities of three months or less.”

Note 4. Variable Interest Entities, page F-18

Confidential Treatment Request by Marathon Oil Corporation

Comment 5

We note that you deconsolidated Equatorial Guinea LNG Holdings (“EGHoldings”) effective May 1, 2007 and now report your 60 percent interest as an equity investment. Please clarify how you determined that EGHoldings is no longer a VIE pursuant to paragraph 5 of FIN 46 (R). Explain how the design changed once EGHoldings commenced primary operations and began to generate revenue and how this impacted your equity investment. In addition, clarify how you determined that it was appropriate to change from consolidation to the equity method on a prospective basis.

Response

FIN No. 46(R) paragraph 11 states that “A development stage entity is a variable interest entity if it meets one of the conditions in paragraph 5.” Prior to commencing its primary operations, EGHoldings was considered to be a development stage enterprise as defined in paragraph 8 of SFAS No. 7, Accounting and Reporting by Development Stage Enterprises, which states “an enterprise shall be considered to be in the development stage if it is devoting substantially all of its efforts to establishing a new business and either one of the following conditions exists:

Planned principal operations have not commenced.

Planned principal operations have commenced, but there has been no significant revenue therefrom.”

During construction of the LNG production facility, EGHoldings also met condition (a) in paragraph 5 of FIN No. 46(R), as its equity at risk was not sufficient to permit it to finance its activities without additional financial support from its equity owners because the construction was financed entirely through shareholder contributions rather than third-party financing. As a result, EGHoldings met the definition of a VIE during this period.

Though there was no change in the design or structure of the entity, once the LNG production facility commenced its primary operations and began to generate revenue in May 2007, we were required to reconsider the sufficiency of EGHoldings’ equity investment under paragraph 11 of FIN No. 46(R) which states, “However, sufficiency of the equity investment should be reconsidered as required by paragraph 7, for example, when the entity undertakes additional activities or acquires additional assets.” Condition (d) in paragraph 7 of FIN No. 46(R) indicates that the initial determination whether an entity is a VIE shall be reconsidered if “the entity receives an additional equity investment that is at risk, or the entity curtails or modifies its activities in a way that decreases its expected losses.” We concluded that EGHoldings was no longer a VIE based on the following two factors:

It ceased being a development stage enterprise under SFAS No. 7 as principal operations and shipments of LNG had begun, thus generating revenues for the entity; and

Confidential Treatment Request by Marathon Oil Corporation

Its total equity investment at risk was then sufficient to permit the entity to finance its activities.

Once EGHoldings was no longer a VIE, we were no longer allowed to consolidate the entity under FIN No. 46(R). We also were not allowed to consolidate EGHoldings under SFAS No. 94, Consolidation of All Majority-owned Subsidiaries, despite the fact that we hold majority ownership, because the minority shareholders have rights limiting our ability to exercise control over the entity. As our investment in EGHoldings gives us the ability to exercise significant influence over its operating and financial policies, we are required by APB Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock, to account for this investment under the equity method of accounting.

This reconsideration did not represent a change in the reporting entity or a change in accounting policy and therefore retroactive application under SFAS No. 154, Accounting Changes and Error Corrections, did not apply. Prospective application is also consistent with the guidance in the SEC Accounting Disclosure Rules and Practices, Topic One, Item IV. General Considerations (All Filings) which states that a change from consolidation to equity method is “usually not reflected retroactively. Change is accounted for prospectively from the date of change.”

Note 6. Acquisition, page F-19

Comment 6

Please provide your asset, investment and income significance analysis of the Western Oil Sands acquisition in accordance with Regulation S-X, Rules 3-05(b) and 11-01(b).

Response

See Attachment B for the asset, investment and income tests that indicate each is below the 20 percent threshold for significance.

Note 9 – Segment Information, page F-24

Comment 7

Expand your footnote to include a reconciliation of the total of the reportable segments’ revenues to your consolidated revenues as presented on your consolidated statements of income. Refer to the requirements of SFAS 131, paragraph 32(a). In addition, please ensure that any discussion of total revenue agrees to your consolidated revenue reported on your statements of income, not total segment revenue. In this respect, your disclosure of total revenue on page 45 should agree to your consolidated results.

Confidential Treatment Request by Marathon Oil Corporation

Response

Consolidated revenues are comprised of the following three line items in the consolidated statements of income:

	2007		2006		2005

Sales and other operating revenues (including consumer excise taxes)	$	62,800	$	57,973	$	48,948
Revenues from matching buy/sell transactions		127		5,457		12,636
Sales to related parties		1,625		1,466		1,402

Consolidated revenues	$	64,552	$	64,896	$	62,986

The other three line items within the Revenues and Other Income section of the consolidated statements of income (i.e., Income from equity method investees, Net gain on disposal of assets and Other income) are not revenues, but rather represent other income items. As such, the total of segment revenues presented in Note 9 - Segment Information and in Management’s Discussion and Analysis of Results of Operations on page 45 agrees with Consolidated revenues as presented in the consolidated statements of income.

_____________________________

Marathon acknowledges that (a) the adequacy and accuracy of the disclosure in the filing are Marathon’s responsibility, (b) the staff’s comments or changes made in response to the staff’s comments do not foreclose the Commission from taking any action on the filing, and (c) Marathon may not assert the staff’s comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Please acknowledge receipt of this response letter by electronic confirmation.

Please call the undersigned at 713-296-4131, Michael K. Stewart, Vice President, Accounting and Controller at 713-296-4333 or Richard J. Kolencik, General Attorney at 713-296-2535, if you have any questions regarding this submission.

	Very truly yours,

	/s/ Janet F. Clark
	Janet F. Clark
	Executive Vice President and Chief Financial Officer

Confidential Treatment Request by Marathon Oil Corporation

Attachment A

Form 10-K - Item 1. Business – Exploration and Production – Production (including development activities)

Equatorial Guinea – We own a 63 percent operated working interest in the Alba field offshore Equatorial Guinea and a 52 percent interest in an onshore liquefied petroleum gas (“LPG”) processing plant held through an equity method investee. During 2007, net liquid hydrocarbon sales averaged 45 mbpd, or 34 percent of our international liquid hydrocarbon sales volumes, and net natural gas sales averaged 228 mmcfd, or 51 percent of our international natural gas sales volumes. Net liquid hydrocarbon sales volumes in 2007 included 33 mbpd of condensate and 12 mbpd of LPG.

We also own a 52 percent interest in Alba Plant LLC, an equity method investee that operates an onshore liquefied petroleum gas (“LPG”) processing plant. Alba field natural gas is supplied to the LPG plant under a long-term contract at a fixed price. During 2007, a gross 846 mmcfd of natural gas was supplied to the LPG production facility and our net liquid hydrocarbon sales volumes in 2007 included 12 mbpd of LPG and 4 mbpd of condensate produced by Alba Plant LLC. As part of our Integrated Gas segment, we own 45 percent of Atlantic Methanol Production Company LLC (“AMPCO”) and 60 percent of Equatorial Guinea LNG Holdings Limited (“EGHoldings”). AMPCO operates a methanol plant and EGHoldings operates an LNG production facility, both located on Bioko Island. Alba field dry natural gas, which remains after the condensate and LPG are removed, is supplied to both of these facilities under long-term contracts at fixed prices. Because of the location of and limited local demand for natural gas in Equatorial Guinea, we consider the prices under the contracts with Alba Plant LLC, AMPCO and EGHoldings to be comparable to the price that could be realized from transactions with unrelated parties in this market under the same or similar circumstances. Our share of the income ultimately generated by the subsequent export of LPG produced by Alba Plant LLC is reflected in our E&P segment. Our share of the income ultimately generated by the subsequent export of methanol produced by AMPCO and LNG produced by EGHoldings is reflected in our Integrated Gas segment as discussed below. During 2007, a gross 130 mmcfd of dry natural gas was supplied to the methanol plant and a gross 268 mmcfd of dry gas was supplied to the LNG production facility. Any remaining dry gas is returned offshore and reinjected into the Alba reservoir for later production.

Form 10-K and Form 10-Q - Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Management’s Discussion and Analysis of Results of Operations – Consolidated Results of Operations – E&P segment revenues

…While international natural gas sales volumes increased, the majority of the increase was due to sales to the EGHoldings the start-up of the LNG production facility in Equatorial Guinea that began operations in the second quarter of 2007. This increase in fixed-price sales volumes also contributed to the decline in our average international natural gas realizations. Our share of the income ultimately generated by the subsequent export of LNG produced by EGHoldings, as well as methanol produced by AMPCO, is reflected in our Integrated Gas segment as discussed below.

Confidential Treatment Request by Marathon Oil Corporation

E&P Operating Statistics	2007		2006		2005

Net Liquid Hydrocarbon Sales (Thousands of barrels per day)(a)
United States		64		76		76
Europe(b)		33		35		36
Africa(b)		100		112		52
Total International(b)		133		147		88
Worldwide Continuing Operations		197		223		164
Discontinued Operations(c)		-		12		27
WORLDWIDE		197		235		191

Net Natural Gas Sales (Millions of cubic feet per day)(d)(e)
United States		477		532		578
Europe		216		243		262
Africa		232		72		92
Total International		448		315		354
WORLDWIDE		925		847		932
Total Worldwide Sales (Thousands of barrels of oil equivalent per day)
Continuing Operations		351		365		319
Discontinued Operations		-		12		27
WORLDWIDE		351		377		346

Average Realizations(f)
Liquid Hydrocarbons (Dollars per barrel)
United States	$	60.15	$	54.41	$	45.41
Europe		70.31		64.02		52.99
Africa		66.09		59.83		46.27
Total International		67.15		60.81		49.04
Worldwide Continuing Operations		64.86		58.63		47.35
Discontinued Operations		-		38.38		33.47
WORLDWIDE	$	64.86	$	57.58	$	45.42

Natural Gas (Dollars per thousand cubic feet)
United States	$	5.73	$	5.76	$	6.42
Europe		6.53		6.74		5.70
Africa (g)		0.25		0.27		0.25
Total International		3.28		5.27		4.28
WORLDWIDE	$	4.54	$	5.58	$	5.61

(a)	Includes crude oil, condensate and natural gas liquids.

(b)	Represents equity tanker liftings and direct deliveries of liquid hydrocarbons. The amounts correspond with the basis for fiscal settlements with governments. Crude oil purchases, if any, from host governments are excluded.

(c)	Represents Marathon’s Russian oil exploration and production businesses that were sold in June 2006.

(d)	Represents net sales after royalties, except for Ireland where amounts are before royalties.

(e)	Includes natural gas acquired for injection and subsequent resale of 47, 46 and 38 mmcfd in 2007, 2006 and 2005.

(f)	Excludes gains and losses on traditional derivative instruments and the unrealized effects of long-term U.K. natural gas contracts that are accounted for as derivatives.

(g)	Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO and EGHoldings, equity method investees. We include our share of Alba Plant LLC’s income in our E&P segment and we include our share of AMPCO’s and EGHoldings’ income in our Integrated Gas segment.

Confidential Treatment Request by Marathon Oil Corporation

Attachment B

Marathon Oil Corporation (MRO)

Western Oil Sands Inc. Significance Tests

Asset Test

As of December 31, 2006

(in thousands)
MRO Total Assets (U.S. GAAP)				Western Oil Sands Total Assets (U.S. GAAP)

	30,831,000		USD		1,754,573		CAD (a)
	20	%			0.85807		exchange rate (b)
	6,166,200				1,505,546		USD
					4.9	%

Does not meet significance test

(a)	Used Western's total assets due to value being far less than 20% of MRO's total assets (i.e., did not exclude assets of WesternZagros, a subsidiary spun off prior to acquisition)

(b)	Exchange rate as of 12/31/06

Marathon Oil Corporation (MRO)

Western Oil Sands Inc. Significance Tests

Income Test

For the year ended December 31, 2006

(in thousands)
MRO Income from Cont. Ops. (U.S. GAAP)				Western Oil Sands Income from Cont. Ops. (U.S. GAAP)

	4,957,000		USD		62,433		CAD (a)
	20	%			0.88378		exchange rate (b)
	991,400				55,177		USD
					1.1	%

Does not meet significance test

(a)	Used Western's total income due to value being far less than 20% of MRO's total income (i.e., did not exclude WesternZagros loss as was not significant)

(b)	Average 2006 exchange rate

Confidential Treatment Request by Marathon Oil Corporation

Marathon Oil Corporation (MRO)

Western Oil Sands Inc. Significance Tests

Investment Test

Assets as of December 31, 2006

(in thousands)
MRO Total Assets (U.S. GAAP)				Western Oil Sands Estimated Investment

	30,831,000,000		USD		34,283,349		Shares
	20	%			55.70		Share price (USD) (a)
	6,166,200,000				1,909,582,539		Shares consideration (USD)

					3,807,847,771		Cash consideration (CDN)
					0.9746		Exchange rate
					3,907,087,801		Cash consideration (USD)

					26,400,000		Estimated transaction costs (USD) (b)

					0		WOS debt guaranteed or legally assumed (USD) (c)
					5,843,070,340		Total Estimated Investment (USD)
					19.0	%

(a)	Average share price for the 5 trading days surrounding announcement

(b)	Includes investment banker, legal and accounting fees, plus contingency for potential unidentified costs [When finalized, actual transaction costs totaled $16MM.]

(c)

Per the SEC Accounting Disclosure Rules and Practices, Topic Two, Item I.D.1.a., "Investment" means total consideration, including any assumed debt for which the registrant is the legal obligor, and costs of acquisition that will be allocated to assets and liabilities acquired. Marathon did not become the legal obligor of Western's debt at the acquisition date (i.e., no guarantee or legal assumption) and no advances were made.