Marathon Oil (MRO)

Proved Liquid Hydrocarbon and Natural Gas Reserves

We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved liquid hydrocarbon and natural gas reserves, both developed and undeveloped. The existence and the estimated amount of proved reserves affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depreciated, depleted or amortized into net income and the presentation of supplemental information on oil and gas producing activities. Both the expected future cash flows to be generated by oil and gas producing properties used in testing such properties for impairment and the expected future taxable income available to realize deferred tax assets also rely, in part, on estimates of net recoverable quantities of liquid hydrocarbons and natural gas.

Proved reserves are the estimated quantities of liquid hydrocarbons and natural gas that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, operational, economic and political conditions change. During 2008, net revisions of previous estimates increased total proved reserves by 23 million boe (less than 2 percent of the beginning of the year reserve estimate).

Our estimation of net recoverable quantities of liquid hydrocarbons and natural gas is a highly technical process performed by in-house teams of reservoir engineers and geoscience professionals. All estimates prepared by these teams are made in compliance with SEC Rule 4-10(a)(2),(3) and (4) of Regulation S-X and 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),” and disclosed in accordance with the requirements of SFAS No. 69, “Disclosures about Oil and Gas Producing Activities (an Amendment of FASB Statements 19, 25, 33 and 39).” The SEC has amended its disclosure requirements effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009 – see Management’s Discussion and Analysis of Financial Condition and Results of Operations – Accounting Standards Not Yet Adopted for additional information. Estimates of liquid hydrocarbon and natural gas reserves are based on prices at December 31, 2008. Reserve estimates are reviewed and approved by our Corporate Reserves Group. Any change to proved reserves estimates in excess of 2.5 million boe on a total-field basis, within a single month, must be approved by the Director of Corporate Reserves, who reports to our Chief Financial Officer. The Corporate Reserves Group may also perform separate, detailed technical reviews of reserve estimates for significant fields that were acquired recently or for properties with problematic indicators such as excessively long lives, sudden changes in performance or changes in economic or operating conditions.

Third-party consultants are engaged to prepare independent reserve estimates for fields that comprise the top 80 percent of our total reserves over a rolling four-year period. We met this goal for the four-year period ended December 31, 2008. For 2006 and thereafter, we established a tolerance level of 10 percent for third-party reserve estimates such that the third-party consultants discontinue their estimation activities once their results are within 10 percent of our internal estimates. Should the third-party consultants’ initial analysis fail to reach our tolerance level, the consultants re-examine the information provided, request additional data and refine their analysis if appropriate. If, after this re-examination, the third-party consultants cannot arrive at estimates within our tolerance, we adjust our reserve estimates as necessary to achieve estimates within our tolerance level. This independent third-party reserve estimation process did not result in significant changes to our reserve estimates in 2008, 2007, or 2006.

The reserves of the Alba field in Equatorial Guinea comprise approximately 38 percent of our total proved liquid hydrocarbon and natural gas reserves as of December 31, 2008. The reserves of the next five largest asset groups – the Waha concessions in Libya, the Alvheim/Vilje development offshore Norway, the Droshky development in Green Canyon Block 244 in the Gulf of Mexico, the Oregon Basin field in the Rocky Mountain area of the United States and the Foinaven development in the North Sea – comprise 32 percent of our total proved liquid hydrocarbon and natural gas reserves.

Depreciation and depletion of producing liquid hydrocarbon and natural gas properties is determined by the units-of-production method and could change with revisions to estimated proved developed reserves. The change in the depreciation and depletion rate over the past three years due to revisions of previous reserve estimates has not been significant. On average, a five percent increase in the amount of liquid hydrocarbon and natural gas reserves would lower the depreciation and depletion rate by approximately $0.47 per barrel, which would increase pretax

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income by approximately $66 million annually, based on 2008 production. On average, a five percent decrease in the amount of liquid hydrocarbon and natural gas reserves would increase the depreciation and depletion rate by approximately $0.52 per barrel and would result in a decrease in pretax income of approximately $73 million annually, based on 2008 production.

Proved Liquid Hydrocarbon and Natural Gas Reserves

We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved liquid hydrocarbon and natural gas reserves, both developed and undeveloped. The existence and the estimated amount of proved reserves affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depreciated, depleted or amortized into net income and the presentation of supplemental information on oil and gas producing activities. Both the expected future cash flows to be generated by oil and gas producing properties used in testing such properties for impairment and the expected future taxable income available to realize deferred tax assets also rely, in part, on estimates of net recoverable quantities of liquid hydrocarbons and natural gas.

Proved reserves are the estimated quantities of liquid hydrocarbons and natural gas that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, operational, economic and political conditions change. During 2008, net revisions of previous estimates increased total proved reserves by 23 million boe (less than 2 percent of the beginning of the year reserve estimate).

Our estimation of net recoverable quantities of liquid hydrocarbons and natural gas is a highly technical process performed by in-house teams of reservoir engineers and geoscience professionals. All estimates prepared by these teams are made in compliance with SEC Rule 4-10(a)(2),(3) and (4) of Regulation S-X and 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),” and disclosed in accordance with the requirements of SFAS No. 69, “Disclosures about Oil and Gas Producing Activities (an Amendment of FASB Statements 19, 25, 33 and 39).” The SEC has amended its disclosure requirements effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009 – see Management’s Discussion and Analysis of Financial Condition and Results of Operations – Accounting Standards Not Yet Adopted for additional information. Estimates of liquid hydrocarbon and natural gas reserves are based on prices at December 31, 2008. Reserve estimates are reviewed and approved by our Corporate Reserves Group. Any change to proved reserves estimates in excess of 2.5 million boe on a total-field basis, within a single month, must be approved by the Director of Corporate Reserves, who reports to our Chief Financial Officer. The Corporate Reserves Group may also perform separate, detailed technical reviews of reserve estimates for significant fields that were acquired recently or for properties with problematic indicators such as excessively long lives, sudden changes in performance or changes in economic or operating conditions.

Third-party consultants are engaged to prepare independent reserve estimates for fields that comprise the top 80 percent of our total reserves over a rolling four-year period. We met this goal for the four-year period ended December 31, 2008. For 2006 and thereafter, we established a tolerance level of 10 percent for third-party reserve estimates such that the third-party consultants discontinue their estimation activities once their results are within 10 percent of our internal estimates. Should the third-party consultants’ initial analysis fail to reach our tolerance level, the consultants re-examine the information provided, request additional data and refine their analysis if appropriate. If, after this re-examination, the third-party consultants cannot arrive at estimates within our tolerance, we adjust our reserve estimates as necessary to achieve estimates within our tolerance level. This independent third-party reserve estimation process did not result in significant changes to our reserve estimates in 2008, 2007, or 2006.

The reserves of the Alba field in Equatorial Guinea comprise approximately 38 percent of our total proved liquid hydrocarbon and natural gas reserves as of December 31, 2008. The reserves of the next five largest asset groups – the Waha concessions in Libya, the Alvheim/Vilje development offshore Norway, the Droshky development in Green Canyon Block 244 in the Gulf of Mexico, the Oregon Basin field in the Rocky Mountain area of the United States and the Foinaven development in the North Sea – comprise 32 percent of our total proved liquid hydrocarbon and natural gas reserves.

Depreciation and depletion of producing liquid hydrocarbon and natural gas properties is determined by the units-of-production method and could change with revisions to estimated proved developed reserves. The change in the depreciation and depletion rate over the past three years due to revisions of previous reserve estimates has not been significant. On average, a five percent increase in the amount of liquid hydrocarbon and natural gas reserves would lower the depreciation and depletion rate by approximately $0.47 per barrel, which would increase pretax

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income by approximately $66 million annually, based on 2008 production. On average, a five percent decrease in the amount of liquid hydrocarbon and natural gas reserves would increase the depreciation and depletion rate by approximately $0.52 per barrel and would result in a decrease in pretax income of approximately $73 million annually, based on 2008 production.

Proved Liquid Hydrocarbon and Natural Gas Reserves

We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved liquid hydrocarbon and natural gas reserves, both developed and undeveloped. The existence and the estimated amount of proved reserves affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depreciated, depleted or amortized into net income and the presentation of supplemental information on oil and gas producing activities. Both the expected future cash flows to be generated by oil and gas producing properties used in testing such properties for impairment and the expected future taxable income available to realize deferred tax assets also rely, in part, on estimates of net recoverable quantities of liquid hydrocarbons and natural gas.

Proved reserves are the estimated quantities of liquid hydrocarbons and natural gas that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. During 2007, net revisions of previous estimates increased total proved reserves by 4 million boe (less than 1 percent of the beginning-of-the-year reserves estimate). Positive revisions of 32 million boe were partially offset by 28 million boe in negative revisions.

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Our estimation of net recoverable quantities of liquid hydrocarbons and natural gas is a highly technical process performed by in-house teams of reservoir engineers and geoscience professionals. All estimates prepared by these teams are made in compliance with SEC Rule 4-10(a)(2),(3) and (4) of Regulation S-X and SFAS No. 25, “Suspension of Certain Accounting Requirements for Oil and Gas Producing Companies (an Amendment of FASB Statement No. 19),” and disclosed in accordance with the requirements of SFAS No. 69, “Disclosures about Oil and Gas Producing Activities (an Amendment of FASB Statements 19, 25, 33 and 39).” Reserve estimates are reviewed and approved by members of our Corporate Reserves Group. Any change to proved reserves estimates in excess of 2.5 million boe on a total-field basis, within a single month, must be approved by the Director of Corporate Reserves, who reports to our Chief Financial Officer. The Corporate Reserves Group may also perform separate, detailed technical reviews of reserve estimates for significant fields that were acquired recently or for properties with problematic indicators such as excessively long lives, sudden changes in performance or changes in economic or operating conditions.

Third-party consultants are engaged to prepare independent reserve estimates for fields that rank in the top 80 percent of our total reserves over a rolling four-year period. The volumes independently estimated are targeted to total at least 80 percent of our total reserves at the beginning of the fourth year. We met this goal for the four-year period ended December 31, 2007. For 2006 and thereafter, we established a tolerance level of 10 percent for third-party reserve estimates such that the third-party consultants discontinue their estimation activities once their results are within 10 percent of our internal estimates. Should the third-party consultants’ initial analysis fail to reach our tolerance level, the consultants re-examine the information provided, request additional data and refine their analysis if appropriate. If, after this re-examination, the third-party consultants cannot arrive at estimates within our tolerance, we would adjust our reserve estimates as necessary. This independent third-party reserve estimation process did not result in significant changes to our reserve estimates in 2007, 2006 or 2005.

The reserves of the Alba field in Equatorial Guinea comprise 39 percent of our total proved liquid hydrocarbon and natural gas reserves as of December 31, 2007. The reserves of the next five largest asset groups – the Waha concessions in Libya, the Alvheim/Vilje development offshore Norway, the Brae area complex offshore the United Kingdom, the Oregon Basin field in the Rocky Mountain area of the United States and the Petronius development on Viosca Knoll Blocks 786 and 830 in the Gulf of Mexico – comprise 31 percent of our total proved liquid hydrocarbon and natural gas reserves.

Depreciation and depletion of producing liquid hydrocarbon and natural gas properties is determined by the units-of-production method and could change with revisions to estimated proved developed reserves. The change in the depreciation and depletion rate over the past three years due to revisions of previous reserve estimates has not been significant. On average, a five percent increase in the amount of liquid hydrocarbon and natural gas reserves would lower the depreciation and depletion rate by approximately $0.66 per barrel, which would increase pretax income by approximately $85 million annually, based on 2007 production. On average, a five percent decrease in the amount of liquid hydrocarbon and natural gas reserves would increase the depreciation and depletion rate by approximately $0.81 per barrel and would result in a decrease in pretax income of approximately $104 million annually, based on 2007 production.

Proved Liquid Hydrocarbon and Natural Gas Reserves