Marathon Oil (MRO)

Estimated Quantities of Proved Bitumen Reserves

The above estimated quantity of net proved bitumen reserves is a forward-looking statement and is based on a number of assumptions, including (among others) commodity prices, volumes in-place, presently known physical data, recoverability of bitumen, industry economic conditions, levels of cash flow from operations, and other operating considerations. To the extent these assumptions prove inaccurate, actual recoveries could be different than current estimates. For a discussion of the proved bitumen reserves estimation process, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Estimates – Estimated Net Recoverable Reserve Quantities – Proved Bitumen Reserves. Operations at the AOSP are not within the scope of Statement of Financial Accounting Standards (“SFAS”) No. 25, “Suspension of Certain Accounting Requirements for Oil and Gas Producing Companies (an Amendment of Financial Accounting Standards Board (“FASB”) Statement No. 19),” SFAS No. 69, “Disclosures about Oil and Gas Producing Activities (an Amendment of FASB Statements 19, 25, 33 and 39),” and Securities and Exchange Commission (“SEC”) Rule 4-10 of Regulation S-X; therefore, bitumen production and reserves are not included in our Supplementary Information on Oil and Gas Producing Activities. The SEC has recently issued a release amending these disclosure requirements effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Accounting Standards Not Yet Adopted for additional information.

Prior to our acquisition of Western, the first fully-integrated expansion of the existing AOSP facilities was approved in 2006. Expansion 1, which includes construction of mining and extraction facilities at the Jackpine mine, expansion of treatment facilities at the existing Muskeg River mine, expansion of the Scotford upgrader and development of related infrastructure, is anticipated to begin operations in late 2010 or 2011. When Expansion 1 is complete, we will have more than 50,000 bpd of net production and upgrading capacity in the Canadian oil sands. The timing and scope of future expansions and debottlenecking opportunities on existing operations remain under review.

During 2008, the Alberta government accepted the project’s application to have a portion of the Expansion 1 capital costs form part of the Muskeg River mine’s allowable cost recovery pool. Due to commodity price declines in the year, royalties for 2008 were one percent of the gross mine revenue.

Commencing January 1, 2009, the Alberta Royalty regime has been amended such that royalty rates will be based on the Canadian dollar (“CAD”) equivalent monthly average West Texas Intermediate (“WTI”) price. Royalty rates will rise from a minimum of one percent to a maximum of nine percent under the gross revenue method and from a minimum of 25 percent to a maximum of 40 percent under the net revenue method. Under both methods, the minimum royalty is based on a WTI price of $55.00 CAD per barrel and below while the maximum royalty is reached at a WTI price of $120.00 CAD per barrel and above, with a linear increase in royalty between the aforementioned prices.

The above discussion of the Oil Sands Mining segment includes forward-looking statements concerning the anticipated completion of AOSP Expansion 1. Factors which could affect the expansion project include transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, delays in obtaining or conditions imposed by necessary government and third-party approvals and other risks customarily associated with construction projects.

Estimated Quantities of Proved Bitumen Reserves

The above estimated quantity of net proved bitumen reserves is a forward-looking statement and is based on a number of assumptions, including (among others) commodity prices, volumes in-place, presently known physical data, recoverability of bitumen, industry economic conditions, levels of cash flow from operations, and other operating considerations. To the extent these assumptions prove inaccurate, actual recoveries could be different than current estimates. For a discussion of the proved bitumen reserves estimation process, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Estimates – Estimated Net Recoverable Reserve Quantities – Proved Bitumen Reserves. Operations at the AOSP are not within the scope of Statement of Financial Accounting Standards (“SFAS”) No. 25, “Suspension of Certain Accounting Requirements for Oil and Gas Producing Companies (an Amendment of Financial Accounting Standards Board (“FASB”) Statement No. 19),” SFAS No. 69, “Disclosures about Oil and Gas Producing Activities (an Amendment of FASB Statements 19, 25, 33 and 39),” and Securities and Exchange Commission (“SEC”) Rule 4-10 of Regulation S-X; therefore, bitumen production and reserves are not included in our Supplementary Information on Oil and Gas Producing Activities. The SEC has recently issued a release amending these disclosure requirements effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Accounting Standards Not Yet Adopted for additional information.

Prior to our acquisition of Western, the first fully-integrated expansion of the existing AOSP facilities was approved in 2006. Expansion 1, which includes construction of mining and extraction facilities at the Jackpine mine, expansion of treatment facilities at the existing Muskeg River mine, expansion of the Scotford upgrader and development of related infrastructure, is anticipated to begin operations in late 2010 or 2011. When Expansion 1 is complete, we will have more than 50,000 bpd of net production and upgrading capacity in the Canadian oil sands. The timing and scope of future expansions and debottlenecking opportunities on existing operations remain under review.

During 2008, the Alberta government accepted the project’s application to have a portion of the Expansion 1 capital costs form part of the Muskeg River mine’s allowable cost recovery pool. Due to commodity price declines in the year, royalties for 2008 were one percent of the gross mine revenue.

Commencing January 1, 2009, the Alberta Royalty regime has been amended such that royalty rates will be based on the Canadian dollar (“CAD”) equivalent monthly average West Texas Intermediate (“WTI”) price. Royalty rates will rise from a minimum of one percent to a maximum of nine percent under the gross revenue method and from a minimum of 25 percent to a maximum of 40 percent under the net revenue method. Under both methods, the minimum royalty is based on a WTI price of $55.00 CAD per barrel and below while the maximum royalty is reached at a WTI price of $120.00 CAD per barrel and above, with a linear increase in royalty between the aforementioned prices.

The above discussion of the Oil Sands Mining segment includes forward-looking statements concerning the anticipated completion of AOSP Expansion 1. Factors which could affect the expansion project include transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, delays in obtaining or conditions imposed by necessary government and third-party approvals and other risks customarily associated with construction projects.