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Exhibit 99.3

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

        Marathon is engaged in worldwide exploration, production and marketing of crude oil and natural gas; domestic refining, marketing and transportation of crude oil and petroleum products, primarily in the Midwest, the upper Great Plains and southeastern United States; and worldwide marketing and transportation of products manufactured from natural gas, such as LNG and methanol, and development of other projects to link stranded natural gas resources with key demand areas. Management's Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with Item 1. Business, Item 1A. Risk Factors, Item 6. Selected Financial Data and Item 8. Financial Statements and Supplementary Data.

        Certain sections of Management's Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements typically contain words such as "anticipates," "believes," "estimates," "expects," "targets," "plans," "projects," "could," "may," "should," "would" or similar words indicating that future outcomes are uncertain. In accordance with "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements.

        Unless specifically noted, amounts for the refining, marketing and transportation segment include the 38 percent interest in MPC held by Ashland prior to the Acquisition on June 30, 2005, and amounts for the integrated gas segment include the 25 percent interest held by SONAGAS (previously held by GEPetrol) in all periods and the 8.5 percent interest held by Mitsui and the 6.5 percent interest held by Marubeni since July 25, 2005.

        Effective January 1, 2006, we revised our measure of segment income to include the effects of minority interests and income taxes related to the segments. In addition, the results of activities primarily associated with the marketing of our equity natural gas production, which had been presented as part of the Integrated Gas segment prior to 2006, are now included in the Exploration and Production segment. Segment results for all periods presented reflect these changes.

Overview

Exploration and Production

        Exploration and production segment revenues correlate closely with prevailing prices for the various qualities of crude oil and natural gas we produce. The increase in our E&P segment revenues in 2006 is primarily related to increased production, particularly from Libya where the first liquid hydrocarbon sales occurred in the first quarter of 2006; however, our 2006 revenues also tracked the changes in market prices for commodities. Higher prices for crude oil early in 2006 reflected concerns about international supply due to unrest in oil-producing countries and the potential for hurricane damage in the U.S. Gulf of Mexico. As hurricane season came to an end without a major storm in the Gulf of Mexico and in the absence of significant international supply shortfalls or disruptions, crude oil prices declined. The average spot price during 2006 for West Texas Intermediate ("WTI"), a benchmark crude oil, was $66.25 per barrel, up from an average of $56.70 in 2005, and ended the year at $61.05. The average differential between WTI and Brent (an international benchmark crude oil) narrowed to $1.07 in 2006 from $2.18 in 2005. Our domestic crude oil production is on average heavier and higher in sulfur content than light sweet WTI. Heavier and higher sulfur crude oil (commonly referred to as heavy sour crude oil) sells at a discount to light sweet crude oil. Our international crude oil production is relatively sweet and is generally sold in relation to the Brent crude benchmark.

        Natural gas prices were lower in 2006 compared to 2005. A significant portion of our United States lower 48 natural gas production is sold at bid-week prices or first-of-month indices relative to our specific producing areas. The average Henry Hub first-of-month price index was $1.41 per mcf lower in 2006 than the 2005 average. Our natural gas prices in Alaska are largely contractual, while natural gas sales there are seasonal in nature, trending down during the second and third quarters of each year and increasing during the fourth and first quarters. Our other major natural gas-producing regions are Europe and Equatorial Guinea, where large portions of our natural gas are sold at contractual prices, making realized prices in these areas less volatile.

        For information on commodity price risk management, see "Item 7A. Quantitative and Qualitative Disclosures about Market Risk."

        E&P segment income during 2006 was up approximately 6 percent from 2005 levels, impacted by increased liquid hydrocarbon sales volumes, primarily due to the resumption of production in Libya, and the higher liquid hydrocarbon prices discussed above, partially offset by higher income taxes, primarily in Libya, operating costs and exploration expenses and decreases in natural gas sales volumes.

Refining, Marketing and Transportation

        RM&T segment income depends largely on our refining and wholesale marketing gross margin, refinery throughputs, retail marketing gross margins for gasoline, distillates and merchandise, and the profitability of our pipeline transportation operations.

        The refining and wholesale marketing gross margin is the difference between the prices of refined products sold and the costs of crude oil and other charge and blendstocks refined, the costs of purchased products and manufacturing expenses, including depreciation. We purchase crude oil to satisfy our refineries' throughput requirements. As a result, our refining and wholesale marketing gross margin could be adversely affected by rising crude oil and other charge and blendstock prices that are not recovered in the marketplace. The crack spread, which is generally a measure of the difference between spot market gasoline and distillate prices and spot market crude oil costs, is a commonly used industry indicator of refining margins. In addition to changes in the crack spread, our refining and wholesale marketing gross margin is impacted by the types of crude oil and other charge and blendstocks we process, the selling prices we realize for all the refined products we sell, the cost of purchased product and our level of manufacturing costs. We process significant amounts of sour crude oil which enhances our competitive position in the industry as sour crude oil typically can be purchased at a discount to sweet crude oil. Over the last three years, approximately 60 percent of the crude oil throughput at our refineries has been sour crude oil. As one of the largest U.S. producers of asphalt, our refining and wholesale marketing gross margin is also impacted by the selling price of asphalt. Sales of asphalt increase during the highway construction season in our market area, which is typically in the second and third quarters of each year. The selling price of asphalt is dependent on the cost of crude oil, the price of alternative paving materials and the level of construction activity in both the private and public sectors. We supplement our refining production by purchasing gasolines and distillates in the spot market to resell at wholesale. In addition, we purchase ethanol for blending with gasoline. Our refining and wholesale marketing gross margin is impacted by the cost of these purchased products, which varies with available supply and demand. Finally, our refining and wholesale marketing gross margin is impacted by changes in manufacturing costs from period to period, which are primarily driven by the level of maintenance activities at the refineries and the price of purchased natural gas used for plant fuel. Our refining and wholesale marketing gross margin has been historically volatile and varies with the level of economic activity in our various marketing areas, the regulatory climate, logistical capabilities and expectations regarding the adequacy of refined product, ethanol and raw material supplies.

        Together with our June 30, 2005 acquisition of the 38 percent minority interest in MPC, our improved refining and wholesale marketing gross margin in 2006 was the key driver of the 72 percent increase in RM&T segment income over 2005. The average refining and wholesale marketing gross margin increased to 22.88 cents per gallon in 2006 from 15.82 cents per gallon in 2005.

        For information on commodity price risk management, see "Item 7A. Quantitative and Qualitative Disclosures about Market Risk."

        Our seven refineries have an aggregate refining capacity of 974 mbpd of crude oil. During 2006, our refineries processed 980 mbpd of crude oil and 234 mbpd of other charge and blend stocks for a crude oil capacity utilization rate of 101 percent.

        Our retail marketing gross margin for gasoline and distillates, which is the difference between the ultimate price paid by consumers and the cost of the refined products, including secondary transportation and consumer excise taxes, also plays an important part in RM&T segment profitability. Factors affecting our retail gasoline and distillate gross margin include competition, seasonal demand fluctuations, the available wholesale supply, the level of economic activity in our marketing areas and weather situations that impact driving conditions. Gross margins on merchandise sold at retail outlets tend to be less volatile than the gross margins from the retail sale of gasoline and distillates. Factors affecting the gross margin on retail merchandise sales include consumer demand for merchandise items, the impact of competition and the level of economic activity in our marketing areas.

        The profitability of our pipeline transportation operations is primarily dependent on the volumes shipped through the pipelines. The volume of crude oil that we transport is directly affected by the supply of, and refiner demand for, crude oil in the markets served directly by our crude oil pipelines. Key factors in this supply and demand balance are the production levels of crude oil by producers, the availability and cost of alternative modes of transportation, and refinery and transportation system maintenance levels. The volume of refined products that we transport is directly affected by the production levels of, and user demand for, refined products in the markets served by our refined product pipelines. In most of our markets, demand for gasoline peaks during the summer driving season, which extends from May through September of each year, and declines during the fall and winter months. The seasonal pattern for distillates is the reverse of this, helping to level overall variability on an annual basis. As with crude oil, other transportation alternatives and system maintenance levels influence refined product movements.

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Integrated Gas

        Our long-term integrated gas strategy is to link stranded natural gas resources with areas where a supply gap is emerging due to declining production and growing demand. LNG, particularly in regard to our operations in Equatorial Guinea, is a key component of this integrated gas strategy. Our integrated gas operations include marketing and transportation of products manufactured from natural gas, such as LNG and methanol, primarily in the United States, Europe and West Africa. Also included in the financial results of the IG segment are the costs associated with ongoing development of certain integrated gas projects. Methanol spot pricing is volatile largely because global methanol demand is 35 million tons and any major unplanned shutdown of or addition to production capacity can have a significant impact on the supply-demand balance.

Corporate

        On April 25, 2007, our Board of Directors declared a two-for-one split of our common stock. The stock split was effected in the form of a stock dividend distributed on June 18, 2007, to stockholders of record at the close of business on May 23, 2007. Stockholders received one additional share of our common stock for each share of common stock held as of the close of business on the record date. Common stock and per share (except par value) information for all periods presented has been restated throughout this document to reflect the stock split.

2006 Operating Highlights

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We announced seven discoveries in Angola and Norway and continued our major development projects, enhancing our E&P operations by:



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Resuming operations and achieving first crude oil liftings in Libya;



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Acquiring leasehold positions in the Bakken Shale in North Dakota and eastern Montana and the Piceance Basin of Colorado and adding acreage in the Barnett Shale in north central Texas;



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Progressing the Alvheim/Vilje development offshore Norway and receiving Norwegian Government approval of the Volund field plan for development and operation that includes its tie-back to Alvheim;



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Progressing the Neptune deepwater Gulf of Mexico development;



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Signing a production sharing contract for the 1.2 million acre Pasangkayu exploration block in Indonesia; and



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Completing the sale of our Russian oil exploration and production businesses at a gain.



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We added net proved oil and natural gas reserves of 146 million boe, excluding 45 million boe of dispositions, while producing 134 million boe during 2006. Over the past three years, we have added net proved reserves of 648 million boe, excluding dispositions of approximately 46 million boe, while producing approximately 380 million boe.



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We achieved record refinery crude oil and total throughput and strengthened our RM&T business by:



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Authorizing the projected $3.2 billion expansion of our Garyville refinery;



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Completing the Tier II ultra-low sulfur diesel fuel projects on time and under budget;



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Forming an ethanol joint venture and beginning construction of the venture's first ethanol plant in Greenville, Ohio;



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Awarding a FEED contract at the Detroit refinery and launching a feasibility study at the Catlettsburg refinery for potential heavy oil upgrading projects; and



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Acquiring strategic marine and terminal assets.



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We increased Marathon Brand gasoline and diesel sales volumes 6 percent in 2006.



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We increased Speedway SuperAmerica's (SSA) same store gasoline and diesel sales volume 2 percent and merchandise sales 8 percent over 2005.



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We advanced our integrated gas strategy by:



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Progressing our Equatorial Guinea LNG production facility to near completion, with commissioning begun in late 2006; and



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Awarding a FEED contract to evaluate a possible second LNG production facility in Equatorial Guinea.

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We issued a request for proposals for a potential Canadian oil sands venture.

Critical Accounting Estimates

        The preparation of financial statements in accordance with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from the estimates and assumptions used.

        Certain accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change; and (2) the impact of the estimates and assumptions on financial condition or operating performance is material.

Estimated Net Recoverable Quantities of Oil and Natural Gas

        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 oil 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 oil and natural gas.

        Proved reserves are the estimated quantities of oil 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 2006, net revisions of previous estimates increased total proved reserves by 83 million boe (6 percent of the beginning-of-the-year reserves estimate). Positive revisions of 98 million boe were partially offset by 15 million boe in negative revisions.

        Our estimation of net recoverable quantities of oil 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 Statement of Financial Accounting Standards ("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)." All 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 make up 80 percent of our reserves over a rolling four-year period. At December 31, 2006 we had met this goal. For 2006, Marathon 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 Marathon's 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 2006, 2005 or 2004.

        The reserves of the Alba field in Equatorial Guinea comprise approximately 40 percent of our total proved oil and natural gas reserves as of December 31, 2006. The next five largest oil and gas producing asset groups – the Waha concessions in Libya, the Alvheim development offshore Norway, the Brae area complex offshore the United Kingdom,

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the Kenai field in Alaska and the Oregon Basin field in the Rocky Mountain area of the United States – comprise a total of approximately 30 percent of our total proved oil and natural gas reserves.

        Depreciation and depletion of producing oil 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. A five percent increase in the amount of oil and natural gas reserves would change the depreciation and depletion rate from $6.92 per barrel to $6.59 per barrel, which would increase pretax income by approximately $45 million annually, based on 2006 production. A five percent decrease in the amount of oil and natural gas reserves would change the depreciation and depletion rate from $6.92 per barrel to $7.28 per barrel and would result in a decrease in pretax income of approximately $50 million annually, based on 2006 production.

Fair Value Estimates

        We are required to develop estimates of fair value to allocate the purchase prices paid to acquire businesses to the assets acquired and liabilities assumed in those acquisitions, to assess impairment of long-lived assets, goodwill and intangible assets and to record non-exchange traded derivative instruments. Other items which require fair value estimates include asset retirement obligations, guarantee obligations and stock-based compensation.

        Under the purchase method of accounting, the purchase price paid to acquire a business is allocated to its assets and liabilities based on the estimated fair values of the assets acquired and liabilities assumed as of the date of acquisition. The excess of the purchase price over the fair value of the net tangible and identifiable intangible assets acquired is recorded as goodwill. The most difficult estimations of individual fair values are those involving property, plant and equipment and identifiable intangible assets. We use all available information to make these fair value determinations and, for certain acquisitions, engage third-party consultants for assistance. During 2005, we made two significant acquisitions with an aggregate purchase price of $3.156 billion that was allocated to the assets acquired and liabilities assumed based on their estimated fair values. See Note 6 to the consolidated financial statements for information on these acquisitions. We did not make any significant acquisitions in 2006. As of December 31, 2006, our recorded goodwill was $1.398 billion. Such goodwill is not amortized, but rather is tested for impairment annually, and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below its carrying value.

        The fair values used to allocate the purchase price of an acquisition and to test goodwill for impairment are often estimated using the expected present value of future cash flows method, which requires us to project related future revenues and expenses and apply an appropriate discount rate. The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain and unpredictable. Accordingly, actual results may differ from the projected results used to determine fair value.

        Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate that the carrying value of the assets may not be recoverable. For purposes of impairment evaluation, long-lived assets must be grouped at the lowest level for which independent cash flows can be identified, which generally is field-by-field for E&P assets, refinery and associated distribution system level or pipeline system level for refining and transportation assets, or site level for retail stores. If the sum of the undiscounted estimated pretax cash flows is less than the carrying value of an asset group, the carrying value is written down to the estimated fair value.

        Estimating the expected future cash flows from our oil and gas producing asset groups requires assumptions about matters such as future oil and natural gas prices, estimated recoverable quantities of oil and natural gas, expected field performance and the political environment in the host country. An impairment of any of our large oil and gas producing properties could have a material impact on our consolidated financial condition and results of operations.

        We evaluate our unproved property investment for impairment based on time or geologic factors in addition to the use of an undiscounted future net cash flow approach. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage are also considered. The expected future cash flows from our RM&T assets require assumptions about matters such as future refined product prices, future crude oil and other feedstock costs, estimated remaining lives of the assets and future expenditures necessary to maintain the assets' existing service potential.

        During 2006, we recorded impairments of $25 million, including $20 million related to the Camden Hills field in the Gulf of Mexico and the associated Canyon Express pipeline. Natural gas production from the Camden Hills field ended during 2006 as a result of increased water production from the well. We did not have significant impairment

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charges during 2005. During 2004, we recorded an impairment of $32 million related to unproved properties and $12 million related to producing properties primarily as a result of unsuccessful developmental drilling activity in Russia.

        We record all derivative instruments at fair value. We have two long-term contracts for the sale of natural gas in the United Kingdom that are accounted for as derivative instruments. These contracts expire in September 2009. These contracts were entered into in the early 1990s in support of our investments in the East Brae field and the SAGE pipeline. Contract prices are linked to a basket of energy and other indices. The contract price is reset annually in October based on the previous twelve-month changes in the basket of indices. Consequently, the prices under these contracts do not track forward natural gas prices. The fair value of these contracts is determined by applying the difference between the contract price and the U.K. forward natural gas strip price to the expected sales volumes under these contracts for the next 18 months. Adjustments to the fair value of these contracts result in non-cash charges or credits to income from operations. The difference between the contract price and the U.K. forward natural gas strip price may fluctuate widely from time to time and may significantly affect income from operations. In 2006, the non-cash gains related to changes in fair value recognized in income from operations were $454 million. Non-cash losses of $386 million and $99 million were recognized in 2005 and 2004. These effects are primarily due to the U.K. 18-month forward natural gas price curve weakening 44 percent in 2006, while it strengthened 90 percent and 36 percent during 2005 and 2004.

Expected Future Taxable Income

        We must estimate our expected future taxable income to assess the realizability of our deferred income tax assets. As of December 31, 2006, we reported net deferred tax assets of $1.865 billion, which represented gross assets of $2.554 billion net of valuation allowances of $689 million.

        Numerous assumptions are inherent in the estimation of future taxable income, including assumptions about matters that are dependent on future events, such as future operating conditions (particularly as related to prevailing oil and natural gas prices) and future financial conditions. The estimates and assumptions used in determining future taxable income are consistent with those used in our internal budgets, forecasts and strategic plans.

        In determining our overall estimated future taxable income for purposes of assessing the need for additional valuation allowances, we consider proved and risk-adjusted probable and possible reserves related to our existing producing properties, as well as estimated quantities of oil and natural gas related to undeveloped discoveries if, in our judgment, it is likely that development plans will be approved in the foreseeable future. In assessing the propriety of releasing an existing valuation allowance, we consider the preponderance of evidence concerning the realization of the impaired deferred tax asset.

        Additionally, we must consider any prudent and feasible tax planning strategies that might minimize the amount of deferred tax liabilities recognized or the amount of any valuation allowance recognized against deferred tax assets, if we can implement these strategies and if we expect to implement these strategies in the event the forecasted conditions actually occurred. The principal tax planning strategy available to us relates to the permanent reinvestment of the earnings of our foreign subsidiaries. Assumptions related to the permanent reinvestment of the earnings of our foreign subsidiaries are reconsidered quarterly to give effect to changes in our portfolio of producing properties and in our tax profile.

Pensions and Other Postretirement Benefit Obligations

        Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the following:

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the discount rate for measuring the present value of future plan obligations;



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the expected long-term return on plan assets;



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the rate of future increases in compensation levels; and



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health care cost projections.

        We develop our demographics and utilize the work of third-party actuaries to assist in the measurement of these obligations. We have selected different discount rates for our funded U.S. pension plans and our unfunded U.S. retiree health plans due to the different projected liability durations of 9 years and 13 years. In determining the assumed discount rates, our methods include a review of market yields on high-quality corporate debt and use of our third-party actuary's discount rate modeling tool. This tool applies a yield curve to the projected benefit plan cash flows

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using a hypothetical Aa yield curve. The yield curve represents a series of annualized individual discount rates from 1.5 to 30 years. The bonds used are rated Aa or higher by a recognized rating agency and only non-callable bonds are included. Each issue is required to have at least $150 million par value outstanding. The top quartile bonds are selected within each maturity group to construct the yield curve.

        The asset rate of return assumption considers the asset mix of the plans (currently targeted at approximately 75 percent equity securities and 25 percent debt securities for the funded pension plans), past performance and other factors. Certain components of the asset mix are modeled with various assumptions regarding inflation, debt returns and stock yields. Our assumptions are compared to those of peer companies and to historical returns for reasonableness and appropriateness.

        Compensation increase assumptions are based on historical experience, anticipated future management actions and demographics of the benefit plans.

        Health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends.

        Note 24 to the consolidated financial statements includes detailed information about the assumptions used to calculate the components of our defined benefit pension and other postretirement plan expense for 2006, 2005 and 2004, as well as the obligations and accumulated other comprehensive income reported on the balance sheets as of December 31, 2006 and 2005.

        Of the assumptions used to measure the December 31, 2006 obligations and estimated 2007 net periodic benefit cost, the discount rate has the most significant effect on the periodic benefit cost reported for the plans. A 0.25 percent decrease in the discount rates of 5.80 percent for our U.S. pension plans and 5.90 percent for our other U.S. postretirement benefit plans would increase pension obligations and other postretirement benefit plan obligations by $93 million and $28 million and would increase defined benefit pension expense and other postretirement plan expense by $13 million and $2 million.

        In 2006, we made certain plan design changes which included an update of the mortality table used in the plans' definition of actuarial equivalence and lump sum calculations and a 20 percent retiree cost of living adjustment for annuitants. This change increased our benefit obligations by $117 million. In 2005, we decreased our retirement age assumption by two years and also increased our lump sum election rate from 90 percent to 96 percent based on changing trends in our experience. This change increased our benefit obligations by $109 million.

Contingent Liabilities

        We accrue contingent liabilities for income and other tax deficiencies, environmental remediation, product liability claims and litigation claims when such contingencies are probable and estimable. Actual costs can differ from estimates for many reasons. For instance, the costs from settlement of claims and litigation can vary from estimates based on differing interpretations of laws, opinions on responsibility and assessments of the amount of damages. Similarly, liabilities for environmental remediation may vary because of changes in laws, regulations and their interpretation; the determination of additional information on the extent and nature of site contamination; and improvements in technology. Our in-house legal counsel regularly assesses these contingent liabilities. In certain circumstances, outside legal counsel is utilized.

        A liability is recorded for these types of contingencies if we determine the loss to be both probable and estimable. We generally record these losses as cost of revenues or selling, general and administrative expenses in the consolidated statements of income, except for tax contingencies, which are recorded as other taxes or provision for income taxes. For additional information on contingent liabilities, see "Management's Discussion and Analysis of Environmental Matters, Litigation and Contingencies."

        An estimate of the sensitivity to net income if other assumptions had been used in recording these liabilities is not practical because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, in terms of both the probability of loss and the estimates of such loss.

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Management's Discussion and Analysis of Results of Operations

Change in Accounting for Matching Buy/Sell Transactions

        Matching buy/sell transactions arise from arrangements in which we agree to buy a specified quantity and quality of crude oil or refined product to be delivered to a specified location while simultaneously agreeing to sell a specified quantity and quality of the same commodity at a specified location to the same counterparty. Prior to April 1, 2006, all matching buy/sell transactions were recorded as separate sale and purchase transactions, or on a "gross" basis. Effective for contracts entered into or modified on or after April 1, 2006, the income effects of matching buy/sell transactions are reported in cost of revenues, or on a "net" basis. Transactions under contracts entered into before April 1, 2006 will continue to be reported on a "gross" basis.

        Each purchase and sale transaction has the characteristics of a separate legal transaction, including separate invoicing and cash settlement. Accordingly, we believed that we were required to account for these transactions separately. An accounting interpretation clarified the circumstances under which a matching buy/sell transaction should be viewed as a single transaction involving the exchange of inventory. For a further description of the accounting requirements and how they apply to matching buy/sell transactions, see Note 2 to the consolidated financial statements.

        This accounting change had no effect on net income but the amounts of revenues and cost of revenues recognized after April 1, 2006 are less than the amounts that would have been recognized under previous accounting practices.

        Additionally, this accounting change impacts the comparability of certain operating statistics, most notably "refining and wholesale marketing gross margin per gallon." While this change does not have an effect on the refining and wholesale marketing gross margin (the numerator for calculating this statistic), sales volumes (the denominator for calculating this statistic) recognized after April 1, 2006 are less than the amount that would have been recognized under previous accounting practices because volumes related to matching buy/sell transactions under contracts entered into or modified on or after April 1, 2006 have been excluded. Accordingly, the resulting refining and wholesale marketing gross margin per gallon statistic will be higher than that same statistic calculated from amounts determined under previous accounting practices. The effect of this change on the refining and wholesale marketing gross margin per gallon for 2006 was not significant.

Consolidated Results of Operations

Revenues for each of the last three years are summarized in the following table:

(In millions)			2006			2005			2004
E&P			$	9,010		$	8,009		$	6,412
RM&T				55,941			56,003			43,630
IG				179			236			190
	Segment revenues			65,130			64,248			50,232
Elimination of intersegment revenues				(688	)		(876	)		(668	)
Gain (loss) on long-term U.K. gas contracts				454			(386	)		(99	)
	Total revenues		$	64,896		$	62,986		$	49,465
Items included in both revenues and costs and expenses:
	Consumer excise taxes on petroleum products and merchandise		$	4,979		$	4,715		$	4,463
	Matching crude oil and refined product buy/sell transactions settled in cash:
		E&P	$	16		$	123		$	167
		RM&T		5,441			12,513			9,075
		Total buy/sell transactions included in revenues	$	5,457		$	12,636		$	9,242

E&P segment revenues increased $1.001 billion in 2006 from 2005 and $1.597 billion in 2005 from 2004. The 2006 increase was primarily in international revenues due to higher realized liquid hydrocarbon prices and sales volumes as illustrated in the table below. The largest liquid hydrocarbon sales volume increase was in Libya, where the first crude oil sales occurred in the first quarter of 2006 and where sales volumes averaged 54 mbpd in 2006, including a total of 8 mbpd that were owed to our account upon the resumption of our operations there. Revenues from domestic operations were flat from year to year. An 8 percent decrease in domestic net natural gas sales volumes, primarily as the result of the Camden Hills field in the Gulf of Mexico ceasing production in early 2006, almost completely offset the benefit of higher liquid hydrocarbon prices in 2006.

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        The 2005 increase in E&P segment revenues over 2004 was primarily the result of higher worldwide liquid hydrocarbon and natural gas prices and international liquid hydrocarbon sales volumes partially offset by lower domestic natural gas and liquid hydrocarbon sales volumes as illustrated in the table below. The decline in domestic volumes in 2005 resulted primarily from weather-related downtime in the Gulf of Mexico and natural declines in field production rates.

E&P Operating Statistics

				2006		2005		2004
Net Liquid Hydrocarbon Sales (mbpd)(a)
	United States				76		76		81
	Europe				35		36		40
	Africa				112		52		32
		Total International(b)			147		88		72
		Worldwide Continuing Operations			223		164		153
		Discontinued Operations(c)			12		27		17
		WORLDWIDE			235		191		170
Net Natural Gas Sales (mmcfd)(d)(e)
	United States				532		578		631
	Europe				243		262		292
	Africa				72		92		76
		Total International			315		354		368
		WORLDWIDE			847		932		999
Total Worldwide Sales (mboepd)
	Continuing operations				365		319		320
	Discontinued operations				12		27		17
		WORLDWIDE			377		346		337
Average Realizations(f)
	Liquid Hydrocarbons ($ per bbl)
		United States		$	54.41	$	45.41	$	32.76
		Europe			64.02		52.99		37.16
		Africa			59.83		46.27		35.11
			Total International		60.81		49.04		36.24
			Worldwide Continuing Operations		58.63		47.35		34.40
			Discontinued Operations		38.38		33.47		22.65
			WORLDWIDE	$	57.58	$	45.42	$	33.31
	Natural Gas ($ per mcf)
		United States		$	5.76	$	6.42	$	4.89
		Europe			6.74		5.70		4.13
		Africa			0.27		0.25		0.25
			Total International		5.27		4.28		3.33
			WORLDWIDE	$	5.58	$	5.61	$	4.31

^(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 46, 38, and 19 mmcfd in 2006, 2005 and 2004, respectively. Effective July 1, 2005, the methodology for allocating sales volumes between natural gas produced from the Brae complex and third-party natural gas production was modified, resulting in an increase in volumes representing natural gas acquired for injection and subsequent resale.

^(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.

        E&P segment revenues included derivative gains of $25 million and $7 million in 2006 and 2005, and derivative losses of $152 million in 2004. Excluded from E&P segment revenues were gains of $454 million in 2006 and losses of $386 million and $99 million in 2005 and 2004 related to long-term natural gas sales contracts in the United Kingdom that are accounted for as derivative instruments. See "Item 7A. Quantitative and Qualitative Disclosures about Market Risk" on page 56.

9

RM&T segment revenues decreased by $62 million in 2006 from 2005 and increased by $12.373 billion in 2005 from 2004. The portion of RM&T revenues reported for matching buy/sell transactions decreased $7.072 billion and increased $3.438 billion in the same periods. The decrease in revenues from matching buy/sell transactions in 2006 was a result of the change in accounting for these transactions effective April 1, 2006, discussed above. Excluding matching buy/sell transactions, 2006 revenues increased primarily as a result of higher refined product prices and sales volumes. The 2005 increase primarily reflected higher refined product and crude oil prices and increased refined product sales volumes, partially offset by decreased crude oil sales volumes.

        For additional information on segment results see page 43.

Income from equity method investments increased by $126 million in 2006 from 2005 and increased by $98 million in 2005 from 2004. Income from our LPG operations in Equatorial Guinea increased in both periods due to higher sales volumes as a result of the plant expansions completed in 2005. The increase in 2005 also included higher PTC income as a result of higher distillate gross margins.

Cost of revenues increased $4.609 billion in 2006 from 2005 and $7.106 billion in 2005 from 2004. In both periods the increases were primarily in the RM&T segment and resulted from increases in acquisition costs of crude oil, refinery charge and blend stocks and purchased refined products. The increase in both periods was also impacted by higher manufacturing expenses, primarily the result of higher contract services and labor costs in 2006 and higher purchased energy costs in 2005.

Purchases related to matching buy/sell transactions decreased $6.968 billion in 2006 from 2005 and increased $3.314 billion in 2005 from 2004, mostly in the RM&T segment. The decrease in 2006 was primarily related to the change in accounting for matching buy/sell transactions discussed above. The increase in 2005 was primarily due to increased crude oil prices.

Depreciation, depletion and amortization increased $215 million in 2006 from 2005 and $125 million in 2005 from 2004. RM&T segment depreciation expense increased in both years as a result of the increase in asset value recorded for our acquisition of the 38 percent interest in MPC on June 30, 2005. In addition, the Detroit refinery expansion completed in the fourth quarter of 2005 contributed to the RM&T depreciation expense increase in 2006. E&P segment depreciation expense for 2006 included a $20 million impairment of capitalized costs related to the Camden Hills field in the Gulf of Mexico and the associated Canyon Express pipeline. Natural gas production from the Camden Hills field ended in 2006 as a result of increased water production from the well.

Selling, general and administrative expenses increased $73 million in 2006 from 2005 and $134 million in 2005 from 2004. The 2006 increase was primarily because personnel and staffing costs increased throughout the year primarily as a result of variable compensation arrangements and increased business activity. Partially offsetting these increases were reductions in stock-based compensation expense. The increase in 2005 was primarily a result of increased stock-based compensation expense, due to the increase in our stock price during that year as well as an increase in equity-based awards, which was partially offset by a decrease in expense as a result of severance and pension plan curtailment charges and start-up costs related to EGHoldings in 2004.

Exploration expenses increased $148 million in 2006 from 2005 and $59 million in 2005 from 2004. Exploration expense related to dry wells and other write-offs totaled $166 million, $111 million and $47 million in 2006, 2005 and 2004. Exploration expense in 2006 also included $47 million for exiting the Cortland and Empire leases in Nova Scotia.

Net interest and other financing costs (income) reflected a net $37 million of income for 2006, a favorable change of $183 million from the net $146 million expense in 2005. Net interest and other financing costs decreased $16 million in 2005 from 2004. The favorable changes in 2006 included increased interest income due to higher interest rates and average cash balances, foreign currency exchange gains, adjustments to interest on tax issues and greater capitalized interest. The decrease in expense for 2005 was primarily a result of increased interest income on higher average cash balances and greater capitalized interest, partially offset by increased interest on potential tax deficiencies and higher foreign exchange losses. Included in net interest and other financing costs (income) are foreign currency gains of $16 million, losses of $17 million and gains of $9 million for 2006, 2005 and 2004.

Minority interest in income of MPC decreased $148 million in 2005 from 2004 due to our acquisition of the 38 percent interest in MPC on June 30, 2005.

Provision for income taxes increased $2.308 billion in 2006 from 2005 and $979 million in 2005 from 2004, primarily due to the $4.259 billion and $2.691 billion increases in income from continuing operations before income taxes. The increase in our effective income tax rate in 2006 was primarily a result of the income taxes related to our Libyan operations, where the statutory income tax rate is in excess of 90 percent. The following is an analysis of the effective income tax rates for continuing operations for 2006, 2005 and 2004. See Note 11 to the consolidated financial statements for further discussion.

		2006		2005		2004
Statutory U.S. income tax rate		35.0	%	35.0	%	35.0	%
Effects of foreign operations, including foreign tax credits		9.9		(0.8	)	0.5
State and local income taxes net of federal income tax effects		1.9		2.5		1.6
Other tax effects		(2.0	)	(0.4	)	(0.9	)
	Effective income tax rate for continuing operations	44.8	%	36.3	%	36.2	%

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Discontinued operations for all periods reflects the operations of our former Russian oil exploration and production businesses which were sold in June 2006. An after-tax gain on the disposal of $243 million is included in discontinued operations for 2006. See Note 7 to the consolidated financial statements for additional information. Also included in 2004 is a $4 million adjustment to the gain on the 2003 sale of our exploration and production operations in western Canada.

Cumulative effect of change in accounting principle in 2005 was an unfavorable effect of $19 million, net of taxes of $12 million, representing the adoption of Financial Accounting Standards Board Interpretation ("FIN") No. 47, "Accounting for Conditional Asset Retirement Obligations – an interpretation of FASB Statement No. 143," as of December 31, 2005.

Segment Results

        Effective January 1, 2006, we revised our measure of segment income to include the effects of minority interests and income taxes related to the segments. In addition, the results of activities primarily associated with the marketing of our equity natural gas production, which had been presented as part of the integrated gas segment prior to 2006, are now included in the exploration and production segment. Segment results for all periods presented reflect these changes.

        As discussed in Note 7 to the consolidated financial statements, we sold our Russian oil exploration and production businesses during 2006. The activities of these operations have been reported as discontinued operations and therefore are excluded from segment results for all periods presented.

Segment income for each of the last three years is summarized and reconciled to net income in the following table.

(In millions)			2006			2005			2004
E&P
	Domestic		$	873		$	983		$	674
	International			1,130			904			416
		E&P segment income		2,003			1,887			1,090
RM&T				2,795			1,628			568
IG				16			55			37
		Segment income		4,814			3,570			1,695
Items not allocated to segments, net of income taxes:
	Corporate and other unallocated items			(212	)		(377	)		(327	)
	Gain (loss) on long-term U.K. natural gas contracts(a)			232			(223	)		(57	)
	Discontinued operations			277			45			(33	)
	Gain on disposition of Syria interest			31			–			–
	Deferred income taxes – tax legislation changes			21			15			–
	– other adjustments(b)			93			–			–
	Loss on early extinguishment of debt			(22	)		–			–
	Gain on sale of minority interests in EGHoldings			–			21			–
	Corporate insurance adjustment(c)			–			–			(17	)
	Cumulative effect of change in accounting principle			–			(19	)		–
		Net income	$	5,234		$	3,032		$	1,261

^(a)

Amounts relate to long-term natural gas contracts in the United Kingdom that are accounted for as derivative instruments and recorded at fair value. See "Critical Accounting Estimates – Fair Value Estimates" on page 37 for further discussion.

^(b)

Other deferred tax adjustments in 2006 represent a benefit recorded for cumulative income tax basis differences associated with prior periods.

^(c)

Insurance expense in 2004 related to estimated future obligations to make certain insurance premium payments related to past loss experience.

United States E&P income decreased $110 million in 2006 from 2005. This was the result of a $182 million decline in pretax income, partially offset by a slight reduction in the effective income tax rate from 37 percent in 2005 to 36 percent in 2006. The decrease in pretax income was due to increases in variable production costs, exploration expenses, property impairments and depreciation, depletion and amortization. Exploration expenses in 2006 were $51 million higher than in 2005, with half of the increase related to a Gulf of Mexico exploratory dry well. As discussed above, U.S. E&P revenues were flat from 2005 to 2006.

        U.S. E&P income increased $309 million in 2005 from 2004. This was the result of a $917 million pretax income increase primarily due to higher revenues as discussed above. The effective income tax rate was 37 percent in both

11

years. Our cost of storm-related repairs as a result of 2005 hurricane activity in the Gulf of Mexico was not significant and our Gulf of Mexico production quickly returned to pre-storm levels. In late September 2004, certain production platforms in the Gulf of Mexico were evacuated due to hurricane activity. All facilities were back on line by October 1, 2004 with the exception of the Petronius platform which came back on line in March 2005. As a result of the damage to the Petronius platform, we recorded expense of $11 million in 2004 representing repair costs incurred, partially offset by the net effects of the property damage insurance recoveries and the related retrospective insurance premiums. We recorded income of $53 million in 2005 and $34 million in 2004 for business interruption insurance recoveries.

International E&P income increased $226 million in 2006 from 2005, reflecting an increase in pretax income of $1.639 billion and an increase in the effective tax rate from 34 percent in 2005 to 62 percent in 2006. The revenue increase discussed above, primarily related to higher liquid hydrocarbon sales volumes and prices in Libya, had the most significant impact on pretax income. Depreciation, depletion and amortization and other variable costs increased with increased production to partially offset the revenue increase. Exploration expenses also increased $97 million in 2006 compared to 2005. Exploration expense related to dry wells and other write-offs was $68 million in 2006 and $44 million in 2005. Also included in 2006 exploration expense was $47 million for exiting the Cortland and Empire leases in Nova Scotia. The increase in the effective income tax rate was primarily the result of the income taxes related to our Libyan operations, where the statutory income tax rate is in excess of 90 percent, and the 2006 increase in the U.K. supplemental corporation tax rate from 10 percent to 20 percent.

        International E&P income increased $488 million in 2005 from 2004, reflecting an increase in pretax income of $740 million and an effective income tax rate of 37 percent in both years. The revenue increase discussed above had the most significant impact on pretax income. Increases in production costs and depletion, depreciation and amortization related primarily to increased production partially offset the benefit of higher revenue. Exploration expenses were also higher in 2005.

RM&T segment income increased $1.167 billion in 2006 from 2005 and $1.060 billion in 2005 from 2004. Segment income in 2006 and 2005 benefited from the 38 percent minority interest in MPC that we acquired on June 30, 2005. Pre-tax income increased by $1.802 billion in 2006 from 2005 and $1.766 billion in 2005 from 2004. The pretax earnings reduction related to the minority interest was $376 million in 2005 and $539 million in 2004. The key driver of the increase in RM&T pretax income in both years was our refining and wholesale marketing gross margin which averaged 22.88 cents per gallon in 2006 compared to 15.82 cents in 2005 and 8.77 cents in 2004. The increase in the margin for 2006 reflected wider crack spreads, improved refined product sales realizations, the favorable effects of our ethanol blending program and increased refinery throughputs. In 2005, the margin improved initially due to wider sweet/sour crude oil differentials and later due to the temporary impact that Hurricanes Katrina and Rita had on refined product prices and concerns about the adequacy of distillate supplies heading into that winter.

        Included in the refining and wholesale marketing gross margin were pretax gains of $400 million in 2006 and pretax losses of $238 million in 2005 and $272 million in 2004 related to derivatives utilized primarily to manage price risk. These derivative gains and losses are largely offset by gains and losses on the physical commodity transactions related to these derivative positions. The change from derivative losses to derivative gains reflects both improvements in the realized effects of our derivatives programs as well as unrealized effects as a result of marking open derivatives positions to market. See further discussion under "Item 7A. Quantitative and Qualitative Disclosures about Market Risk."

        We averaged 980 mbpd of crude oil throughput in 2006, or 101 percent of system capacity. We averaged 973 mbpd of crude oil throughput in 2005 and 939 mbpd in 2004, representing 102 percent and 99 percent of system capacity for those years. Our capacity increased in 2005 as a result of the Detroit refinery expansion from 74 to 100 mbpd.

        The following table includes certain key operating statistics for the RM&T segment for each of the last three years.

RM&T Operating Statistics

	2006		2005		2004
Refining and wholesale marketing gross margin ($ per gallon)(a)	$	0.2288	$	0.1582	$	0.0877
Refined products sales volumes (mbpd)(b)(c)		1,425		1,455		1,400
Matching buy/sell volumes included in refined products sales volumes (mbpd)(c)		24		77		71

^(a)

Sales revenue less cost of refinery inputs, purchased products and manufacturing expenses, including depreciation.

^(b)

Total average daily volumes of refined product sales to wholesale, branded and retail (SSA) customers.

^(c)

On April 1, 2006, we changed our accounting for matching buy/sell transactions as a result of a new accounting standard. This change resulted in lower refined product sales volumes for the remainder of 2006 than would have been reported under the previous accounting practices. See Note 2 to the consolidated financial statements.

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IG segment income decreased $39 million in 2006 from 2005 compared to an increase of $18 million in 2005 from 2004. In 2006, a $17 million pretax loss was recognized as a result of the renegotiation of a technology agreement and income from our equity method investment in AMPCO was lower due to plant downtime during a planned turnaround and subsequent compressor repair, partially offset by higher realized methanol prices. The provision for income taxes also increased $15 million in 2006.

Management's Discussion and Analysis of Financial Condition, Cash Flows and Liquidity

Financial Condition

        Net property, plant and equipment increased $1.642 billion in 2006 primarily as a result of the capital expenditures and the additional capitalized asset retirement costs discussed below. Net property, plant and equipment as of the end of the last two years is summarized in the following table.

(In millions)				2006		2005
E&P
	Domestic			$	3,636	$	2,811
	International				4,879		4,737
		Total E&P			8,515		7,548
RM&T					6,452		6,113
IG					1,378		1,145
Corporate					308		205
			Total	$	16,653	$	15,011

        Asset retirement obligations increased $333 million in 2006 from 2005 primarily due to upward revisions of previous estimates related to increasing cost estimates, primarily in the United Kingdom, and to the accrual of obligations for new properties, primarily the Alvheim/Vilje development in Norway and the LNG production facility in Equatorial Guinea.

Cash Flows

Net cash provided from operating activities totaled $5.488 billion in 2006, compared with $4.738 billion in 2005 and $3.766 billion in 2004. The $750 million increase in 2006 primarily reflects the impact of higher net income, partially offset by contributions of $635 million to our funded defined benefit pension plans and working capital changes. The 2005 increase mainly resulted from higher net income, partially offset by the effects of receivables which were transferred to Ashland at the Acquisition date.

Net cash used in investing activities totaled $2.955 billion in 2006, compared with $3.127 billion in 2005 and $2.324 billion in 2004. Significant investing activities include capital expenditures, acquisitions of businesses and asset disposals.

Capital expenditures by segment for continuing operations for each of the last three years are summarized in the following table.

(In millions)				2006		2005		2004
E&P
	Domestic			$	1,302	$	638	$	405
	International				867		728		435
		Total E&P			2,169		1,366		840
RM&T					916		841		794
IG					307		571		488
Corporate					41		18		19
			Total	$	3,433	$	2,796	$	2,141

        The $637 million increase in capital expenditures in 2006 over 2005 primarily resulted from increased spending in the E&P segment and primarily relates to significant acreage acquisitions in the Bakken Shale in North Dakota and eastern Montana and the Piceance Basin of Colorado, as well as to continued work on the Alvheim/Vilje development offshore Norway and the Neptune development in the Gulf of Mexico. The $264 million decrease in integrated gas spending reflects the fact that the LNG production facility in Equatorial Guinea is nearing completion. The $655 million increase in 2005 capital expenditures over 2004 mainly resulted from increased spending related to the Alvheim development and the Equatorial Guinea LNG production facility.

13

Acquisitions in 2006 primarily included cash payments of $718 million associated with our re-entry into Libya. Acquisitions in 2005 included cash payments of $506 million for the acquisition of Ashland's 38 percent ownership in MPC. For further discussion of acquisitions, see Note 6 to the consolidated financial statements.

Disposal of assets and of discontinued operations totaled $966 million in 2006, compared with $131 million in 2005 and $76 million in 2004. Proceeds of $832 million from the disposal of discontinued operations in 2006 related to the sale of our Russian exploration and production businesses in June 2006. In 2006, other disposals of assets included proceeds from the sale of 90 percent of our interest in Syrian natural gas fields, SSA stores and other domestic production and transportation assets. In 2005 and 2004, proceeds were primarily from the sale of various domestic producing properties and SSA stores.

Net cash used in financing activities totaled $2.581 billion in 2006, compared with $2.345 billion in 2005, and net cash provided of $527 million in 2004. Significant uses of cash in financing activities during 2006 included common stock repurchases under a previously announced plan, which is discussed under Liquidity and Capital Resources, dividend payments, the repayment of our 6.65% notes that matured during 2006 and the early extinguishment of portions of our outstanding debt. The most significant use of cash in 2005 was related to the repayment of $1.920 billion of debt assumed as a part of the acquisition of Ashland's 38 percent of MPC. In 2004, cash provided from financing activities was primarily related to the issuance of 69,000,000 shares of common stock on March 31, 2004, resulting in net proceeds of $1.004 billion. The change from 2004 to 2005 also included an increase in dividends paid and distributions to the minority shareholder of MPC prior to the Acquisition, net of an increase in contributions from the minority shareholders of EGHoldings.

Derivative Instruments

        See "Quantitative and Qualitative Disclosures about Market Risk" on page 56, for a discussion of derivative instruments and associated market risk.

Dividends to Stockholders

        Dividends of $0.76 per common share or $548 million were paid during 2006. On January 29, 2007, our Board of Directors declared a dividend of $0.20 cents per share on our common stock, payable March 12, 2007, to stockholders of record at the close of business on February 21, 2007.

Liquidity and Capital Resources

        Our main sources of liquidity and capital resources are internally generated cash flow from operations, committed credit facilities and access to both the debt and equity capital markets. Our ability to access the debt capital market is supported by our investment grade credit ratings. Our senior unsecured debt is currently rated investment grade by Standard and Poor's Corporation, Moody's Investor Services, Inc. and Fitch Ratings with ratings of BBB+, Baa1, and BBB+. Because of the liquidity and capital resource alternatives available to us, including internally generated cash flow, we believe that our short-term and long-term liquidity is adequate to fund operations, including our capital spending programs, stock repurchase program, repayment of debt maturities and any amounts that may ultimately be paid in connection with contingencies.

        During 2006, we entered into an amendment to our $1.5 billion five-year revolving credit agreement, expanding the size of the facility to $2.0 billion and extending the termination date from May 2009 to May 2011. Concurrent with this amendment, the $500 million MPC revolving credit facility was terminated. At December 31, 2006, there were no borrowings against this facility. At December 31, 2006, we had no commercial paper outstanding under our U.S. commercial paper program that is backed by the five-year revolving credit facility.

        During 2006 we entered into a loan agreement which allows borrowings of up to $525 million from the Norwegian export credit agency based upon the amount of qualifying purchases by Marathon of goods and services from Norwegian suppliers. The loan agreement provides for either a fixed or floating interest rate option at the time of the initial drawdown. Should we elect to borrow under the agreement, the initial drawdown can only occur in June 2007.

        As a condition of the closing agreements for the Acquisition, we are required to maintain MPC on a stand-alone basis financially through June 30, 2007. During this period of time, capital contributions into MPC are prohibited and MPC is prohibited from incurring additional debt, except for borrowings under an existing intercompany loan facility to fund an expansion project at MPC's Detroit refinery and in the event of limited extraordinary circumstances. There are no restrictions against MPC making intercompany loans or declaring dividends to its parent. We believe that the

14

existing cash balances of MPC and cash provided from its operations will be adequate to meet its stand-alone liquidity requirements over the remainder of this two-year period.

        As of December 31, 2006, there was $1.7 billion aggregate amount of common stock, preferred stock and other equity securities, debt securities, trust preferred securities or other securities, including securities convertible into or exchangeable for other equity or debt securities available to be issued under the $2.7 billion universal shelf registration statement filed with the Securities and Exchange Commission in 2002.

        Our cash-adjusted debt-to-capital ratio (total-debt-minus-cash to total-debt-plus-equity-minus-cash) was six percent at December 31, 2006, compared to 11 percent at year-end 2005 as shown below. This includes $519 million of debt that is serviced by United States Steel.

(Dollars in millions)                  December 31		2006			2005
Long-term debt due within one year		$	471		$	315
Long-term debt			3,061			3,698
	Total debt	$	3,532		$	4,013
Cash		$	2,585		$	2,617
Equity		$	14,607		$	11,705
Calculation:
Total debt		$	3,532		$	4,013
Minus cash			2,585			2,617
	Total debt minus cash		947			1,396
Total debt			3,532			4,013
Plus equity			14,607			11,705
Minus cash			2,585			2,617
	Total debt plus equity minus cash	$	15,554		$	13,101
Cash-adjusted debt-to-capital ratio			6	%		11	%

        During 2006, we extinguished portions of our outstanding debt with a total face value of $162 million. The debt was repurchased at a weighted average price equal to 122 percent of face value. We will continue to evaluate debt repurchase opportunities as they arise.

        Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance (as measured by various factors including cash provided from operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies.

Stock Repurchase Program

        In January 2006, we announced a $2 billion share repurchase program. In January 2007, our Board of Directors authorized the extension of this share repurchase program by an additional $500 million. As of February 21, 2007, we had repurchased 48.3 million common shares at a cost of $2 billion. We anticipate completing the additional $500 million in share repurchases during the first half of 2007. Purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions. We will use cash on hand, cash generated from operations or cash from available borrowings to acquire shares. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion.

        The forward-looking statements about our common stock repurchase program are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially are changes in prices of and demand for crude oil, natural gas and refined products, actions of competitors, disruptions or interruptions of our production or refining operations due to unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other operating and economic considerations.

15

Contractual Cash Obligations

        The table below provides aggregated information on our obligations to make future payments under existing contracts as of December 31, 2006.

Summary of Contractual Cash Obligations

(In millions)			Total		2007		2008- 2009		2010- 2011		Later Years
Long-term debt (excludes interest)(a)(b)			$	3,398	$	450	$	400	$	143	$	2,405
Sale-leaseback financing (includes imputed interest)(a)				75		20		22		22		11
Capital lease obligations(a)				141		16		33		33		59
Operating lease obligations(a)				851		154		286		158		253
Operating lease obligations under sublease(a)				32		5		11		11		5
Purchase obligations:
	Crude oil, refinery feedstock, refined product and ethanol contracts(c)			14,419		12,588		852		655		324
	Transportation and related contracts			1,445		515		323		201		406
	Contracts to acquire property, plant and equipment			1,703		935		719		37		12
	LNG terminal operating costs(d)			178		13		24		25		116
	Service and materials contracts(e)			602		210		231		81		80
	Unconditional purchase obligations(f)			62		7		14		14		27
	Commitments for oil and gas exploration (non-capital)(g)			100		57		31		2		10
		Total purchase obligations		18,509		14,325		2,194		1,015		975
Other long-term liabilities reported in the consolidated balance sheet:
	Defined benefit postretirement plan obligations(h)			1,627		97		164		276		1,090
Total contractual cash obligations(i)			$	24,633	$	15,067	$	3,110	$	1,658	$	4,798

^(a)

Upon the Separation, United States Steel assumed certain debt and lease obligations. Such amounts are included in the above table because Marathon remains primarily liable.

^(b)

We anticipate cash payments for interest of $227 million for 2007, $364 million for 2008-2009, $357 million for 2010-2011 and $1.387 billion for the remaining years for a total of $2.335 billion.

^(c)

The majority of these contractual obligations as of December 31, 2006 relate to contracts to be satisfied within the first 180 days of 2007. These contracts include variable price arrangements and some contracts are accounted for as nontraditional derivatives.

^(d)

We have acquired the right to deliver 58 bcf of natural gas per year to the Elba Island LNG re-gasification terminal. The agreement's primary term ends in 2021. Pursuant to this agreement, we are also committed to pay for a portion of the operating costs of the terminal.

^(e)

Service and materials contracts include contracts to purchase services such as utilities, supplies and various other maintenance and operating services.

^(f)

We are a party to a long-term transportation services agreement with Alliance Pipeline. This agreement is used by Alliance Pipeline to secure its financing. This arrangement represents an indirect guarantee of indebtedness. Therefore, this amount has also been disclosed as a guarantee. See Note 30 to the consolidated financial statements for a complete discussion of our guarantee.

^(g)

Commitments for oil and gas exploration (non-capital) include estimated costs related to contractually obligated exploratory work programs that are expensed immediately, such as geological and geophysical costs.

^(h)

We have obligations consisting of pensions and other postretirement benefits including medical and life insurance. We have estimated projected funding requirements through 2016.

⁽ⁱ⁾

Includes $581 million of contractual cash obligations that have been assumed by United States Steel. For additional information, see "Management's Discussion and Analysis of Financial Condition, Cash Flows and Liquidity – Obligations Associated with the Separation of United States Steel – Summary of Contractual Cash Obligations Assumed by United States Steel" on page 49.

Off-Balance Sheet Arrangements

        Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under generally accepted accounting principles. Although off-balance sheet arrangements serve a variety of our business purposes, we are not dependent on these arrangements to maintain our liquidity and capital resources; and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on liquidity and capital resources.

        We have provided various forms of guarantees to unconsolidated affiliates, United States Steel and others. These arrangements are described in Note 30 to the consolidated financial statements.

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We are a party to an agreement that would require us to purchase, under certain circumstances, the interest in Pilot Travel Centers LLC ("PTC") not currently owned. This put/call agreement is described in Note 30 to the consolidated financial statements.

Nonrecourse Indebtedness of Investees

        Certain of our investees have incurred indebtedness that we do not support through guarantees or otherwise. If we were obligated to share in this debt on a pro rata ownership basis, our share would have been $340 million as of December 31, 2006. Of this amount, $217 million relates to PTC. If any of these investees default, we have no obligation to support the debt. Our partner in PTC has guaranteed $75 million of the total PTC debt.

Obligations Associated with the Separation of United States Steel

        On December 31, 2001, we disposed of our steel business through a tax-free distribution of the common stock of our wholly owned subsidiary, United States Steel, to holders of our USX – U. S. Steel Group class of common stock in exchange for all outstanding shares of Steel Stock on a one-for-one basis.

        We remain obligated (primarily or contingently) for certain debt and other financial arrangements for which United States Steel has assumed responsibility for repayment under the terms of the Separation. United States Steel's obligations to Marathon are general unsecured obligations that rank equal to United States Steel's accounts payable and other general unsecured obligations. If United States Steel fails to satisfy these obligations, we would become responsible for repayment. Under the Financial Matters Agreement, United States Steel has all of the existing contractual rights under the leases assumed from Marathon, including all rights related to purchase options, prepayments or the grant or release of security interests. However, United States Steel has no right to increase amounts due under or lengthen the term of any of the assumed leases, other than extensions set forth in the terms of the assumed leases.

        As of December 31, 2006, we have identified the following obligations totaling $564 million that have been assumed by United States Steel:

•

$415 million of industrial revenue bonds related to environmental improvement projects for current and former United States Steel facilities, with maturities ranging from 2009 through 2033. Accrued interest payable on these bonds was $11 million at December 31, 2006.



•

$60 million of sale-leaseback financing under a lease for equipment at United States Steel's Fairfield Works, with a term extending to 2012, subject to extensions. There was no accrued interest payable on this financing at December 31, 2006.



•

$44 million of obligations under a lease for equipment at United States Steel's Clairton coke-making facility, with a term extending to 2012. There was no accrued interest payable on this financing at December 31, 2006.



•

$34 million of operating lease obligations, $31 million of which was in turn assumed by purchasers of major equipment used in plants and operations divested by United States Steel.



•

A guarantee of all obligations of United States Steel as general partner of Clairton 1314B Partnership, L.P. to the limited partners. United States Steel has reported that it currently has no unpaid outstanding obligations to the limited partners. For further discussion of the Clairton 1314B guarantee, see Note 3 to the consolidated financial statements.

        Of the total $564 million, obligations of $530 million and corresponding receivables from United States Steel were recorded on our consolidated balance sheet as of December 31, 2006 (current portion – $32 million; long-term portion – $498 million). The remaining $34 million was related to off-balance sheet arrangements and contingent liabilities of United States Steel.

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        The table below provides aggregated information on the portion of our obligations to make future payments under existing contracts that have been assumed by United States Steel as of December 31, 2006:

Summary of Contractual Cash Obligations Assumed by United States Steel

(In millions)		Total		2007		2008- 2009		2010- 2011		Later Years
Contractual obligations assumed by United States Steel
	Long-term debt(a)	$	415	$	–	$	–	$	–	$	415
	Sale-leaseback financing (includes imputed interest)		75		20		22		22		11
	Capital lease obligations		58		10		19		19		10
	Operating lease obligations		3		3		–		–		–
	Operating lease obligations under sublease		30		5		10		10		5
Total contractual obligations assumed by United States Steel		$	581	$	38	$	51	$	51	$	441

^(a)

We anticipate cash payments for interest of $23 million for 2007, $46 million for 2008-2009, $45 million for 2010-2011 and $239 million for the later years to be assumed by United States Steel.

        Marathon and United States Steel have entered into a tax sharing agreement that allocates tax liabilities relating to taxable periods ended on or before December 31, 2001. In 2006 and 2005, in accordance with the terms of the tax sharing agreement, we paid $35 million and $6 million to United States Steel in connection with the settlement with the Internal Revenue Service of the consolidated federal income tax returns of USX Corporation for the years 1995 through 2001. The final payment of $13 million to United States Steel related to U.S. federal income tax returns under the tax sharing agreement was made in January 2007.

        United States Steel reported in its Form 10-K for the year ended December 31, 2006, that it has significant restrictive covenants related to its indebtedness including cross-default and cross-acceleration clauses on selected debt that could have an adverse effect on its financial position and liquidity. However, United States Steel management believes that its liquidity will be adequate to satisfy its obligations for the foreseeable future.

Transactions with Related Parties

        We own a 63 percent working interest in the Alba field offshore Equatorial Guinea. We own a 52 percent interest in an onshore LPG processing plant in EG through an equity method investee, Alba Plant LLC. Additionally, we own a 45 percent interest in an onshore methanol production plant through AMPCO, an equity method investee. We sell our marketed natural gas from the Alba field to Alba Plant LLC and AMPCO. AMPCO uses the natural gas to manufacture methanol and sells the methanol through another equity method investee, AMPCO Marketing LLC.

        Sales to our 50 percent equity method investee, PTC, which consists primarily of refined petroleum products, accounted for two percent or less of our total sales revenue for 2006, 2005 and 2004. PTC is the largest travel center network in the United States and operates 269 travel centers in the United States and Canada. Prior to the Acquisition on June 30, 2005, Ashland was a related party as a result of its 38 percent minority interest in MPC. During that time, we sold refined petroleum products consisting mainly of petrochemicals, base lube oils and asphalt to Ashland. Our sales to Ashland accounted for less than one percent of our total sales revenue for 2005 and 2004. We believe that these transactions were conducted under terms comparable to those with unrelated parties.

        Marathon holds a 60 percent interest, SONAGAS holds a 25 percent interest, Mitsui holds an 8.5 percent interest and Marubeni holds a 6.5 percent interest in EGHoldings. As of December 31, 2006, total expenditures of $1.363 billion, including $1.300 billion of capital expenditures, related to the Equatorial Guinea LNG production facility have been incurred. Cash of $234 million held in escrow to fund future contributions from SONAGAS to EGHoldings is classified as restricted cash and is included in investments and long-term receivables as of December 31, 2006. Our current receivables from and payables to the interest holders in EGHoldings are $13 million and $232 million as of December 31, 2006, including a payable to SONAGAS of $229 million.

Management's Discussion and Analysis of Environmental Matters, Litigation and Contingencies

        We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and

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location of its operating facilities, marketing areas, production processes and whether it is also engaged in the petrochemical business or the marine transportation of crude oil and refined products.

        Our environmental expenditures for each of the last three years were^(a):

(In millions)			2006		2005		2004
Capital			$	166	$	390	$	433
Compliance
	Operating & maintenance			319		250		215
	Remediation(b)			20		25		32
		Total	$	505	$	665	$	680

^(a)

Amounts are determined based on American Petroleum Institute survey guidelines.

^(b)

These amounts include spending charged against remediation reserves, where permissible, but exclude non-cash provisions recorded for environmental remediation.

        Our environmental capital expenditures accounted for 5 percent of capital expenditures for continuing operations in 2006, 14 percent in 2005 and 20 percent in 2004.

        We accrue for environmental remediation activities when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. As environmental remediation matters proceed toward ultimate resolution or as additional remediation obligations arise, charges in excess of those previously accrued may be required.

        New or expanded environmental requirements, which could increase our environmental costs, may arise in the future. We comply with all legal requirements regarding the environment, but since not all of them are fixed or presently determinable (even under existing legislation) and may be affected by future legislation or regulations, it is not possible to predict all of the ultimate costs of compliance, including remediation costs that may be incurred and penalties that may be imposed.

        Our environmental capital expenditures are expected to be approximately $159 million or 8 percent of capital expenditures in 2007. Predictions beyond 2007 can only be broad-based estimates, which have varied, and will continue to vary, due to the ongoing evolution of specific regulatory requirements, the possible imposition of more stringent requirements and the availability of new technologies, among other matters. Based on currently identified projects, we anticipate that environmental capital expenditures will be approximately $277 million in 2008; however, actual expenditures may vary as the number and scope of environmental projects are revised as a result of improved technology or changes in regulatory requirements and could increase if additional projects are identified or additional requirements are imposed.

        Of particular significance to our refining operations were U.S. EPA regulations that required reduced sulfur levels starting in 2004 for gasoline and 2006 for diesel fuel. We achieved compliance with these regulations and began production of ultra-low sulfur diesel fuel for on-road use prior to the June 1, 2006 deadline. The cost of achieving compliance with these regulations was approximately $850 million. We will also be spending approximately $250 million from 2006 through 2010 to produce ultra-low sulfur diesel fuel for off-road use. Further, we estimate that we will spend approximately $400 million over a four-year period beginning in 2008 to comply with Mobile Source Air Toxics II regulations relating to benzene. This is a preliminary estimate as the Mobile Source Air Toxics II regulations should be finalized in the first half of 2007.

        During 2001, MPC entered into a New Source Review consent decree and settlement of alleged Clean Air Act and other violations with the EPA covering all of its refineries. The settlement committed MPC to specific control technologies and implementation schedules for environmental expenditures and improvements to its refineries over approximately an eight-year period. In addition, MPC has been working on certain agreed upon supplemental environmental projects as part of this settlement of an enforcement action for alleged CAA violations and these have been substantially completed.

        The oil industry across the U.K. continental shelf is making reductions in the amount of oil in its produced water discharges pursuant to the Department of Trade and Industry initiative under the Oil Pollution Prevention and Control Regulations ("OSPAR") of 2005. In compliance with these regulations, we have almost completed our OSPAR project for the Brae field to make the required reductions of oil in its produced water discharges. Our share of capital costs for the project is $7 million.

        For information on legal proceedings related to environmental matters, see "Item 3. Legal Proceedings."

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Outlook

Capital, Investment and Exploration Budget

        We approved a capital, investment and exploration budget of $4.242 billion for 2007, which includes budgeted capital expenditures of $3.886 billion. This represents a 16 percent increase over 2006 actual spending. The primary focus of the 2007 budget is to find additional oil and natural gas reserves, develop existing fields, strengthen RM&T assets and continue implementation of the integrated gas strategy. The budget includes worldwide production spending of $1.429 billion primarily in the United States, Norway, Libya and Ireland. The worldwide exploration budget of $802 million includes plans to drill 14 to 17 significant exploration or appraisal wells. Other activities will focus primarily on areas within or adjacent to our onshore producing properties in the United States. The budget includes $1.464 billion for RM&T, primarily for refining projects including the 180 mbpd Garyville refinery expansion project and the FEED for a potential Detroit refinery heavy oil upgrading project which would allow us to process increased volumes of Canadian oil sands production. The RM&T budget also includes increased investments in transportation and logistics, a strategically important area of the business, including the expansion of our ethanol blending capabilities at terminals in the Midwest and Southeast. The integrated gas budget of $331 million is primarily for completion of the LNG processing facility in Equatorial Guinea, as well as FEED expenditures associated with a potential expansion of that facility. The remaining $216 million is designated for capitalized interest and corporate activities.

Exploration and Production

        The seven announced discoveries in 2006 (six in deepwater Angola and one in Norway) resulted from our balanced exploration strategy which places an emphasis on near-term production opportunities, while retaining an appropriate exposure to longer-term options. Major exploration activities, which are currently underway or under evaluation, include those:

•

offshore Angola, where we have participated in 13 discoveries on Block 31, in which we hold a 10 percent outside-operated interest. In 2006, we announced the Urano, Titania and Terra discoveries, as well as an unnamed discovery. Current plans call for a potential development area in the northeastern part of Block 31, which encompasses the Plutao, Saturno, Marte, Venus and Terra discoveries. The remaining discoveries are being evaluated for potential development. We have secured rig capacity for and plan to participate in exploration wells on Block 31 during 2007;



•

offshore Angola on Block 32 in which we hold a 30 percent outside-operated interest and where we participated in five discoveries through 2006, Gindungo, Canela, Gengibre, Mostarda and Salsa, and announced two additional discoveries in 2007, Manjericao and Caril. These discoveries move Block 32 closer toward establishment of a commercial development. We have secured rig capacity for and plan to participate in exploration wells on Block 32 during 2007;



•

in Equatorial Guinea, where we are evaluating development scenarios for the Deep Luba and Gardenia discoveries on the Alba Block, one of which includes production through the Alba field infrastructure and the future LNG production facility on Bioko Island. We own a 63 percent interest in the Alba Block and serve as operator;



•

in Norway, where we now own interests in 15 licenses in the Norwegian sector of the North Sea and plan to drill one or two exploration wells during 2007; and



•

in the Gulf of Mexico, where we plan to participate in two to three exploration wells during 2007. We have secured rig capacity to drill two wells and our ability to drill the third well depends upon securing additional rig capacity.

        During 2006, we continued to make progress in advancing key development projects that will help serve as the basis for our production growth profile in the coming years. Major development and production activities currently underway or under evaluation include those:

•

in Libya, where we re-entered the Waha concessions at the end of 2005 and achieved first production in January 2006. We continue to work with our partners to maximize the potential of this major asset. We own a 16.33 percent outside-operated interest in the approximately 13 million acre Waha concessions;



•

in Norway, where our Alvheim/Vilje development will consist of a floating production, storage and offloading vessel with subsea infrastructure for five drill centers and associated flow lines. Construction on the project is nearly complete and commissioning has commenced. First production is expected during the second quarter 2007, at which time four wells will be available, and drilling activities will continue into 2008. A peak net production rate of 75 mboepd is expected in early 2008. The Alvheim development includes the Kneler, Boa

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and Kameleon fields in which we own a 65 percent interest and serve as operator. We own a 47 percent outside-operated interest in the nearby Vilje discovery. Also, plans for development of the Volund discovery as a tie-back to the Alvheim development were approved by the Norwegian Government in early 2007. First production is expected from Volund in the second quarter of 2009. We own a 65 percent interest in Volund and serve as operator;

•

in the Gulf of Mexico, where the Neptune development is on target for first production by early 2008. We own a 30 percent outside-operated interest in Neptune;



•

in Ireland, where the Corrib natural gas development project has re-commenced and we expect first production in 2009. We own a 19 percent outside-operated interest in Corrib;



•

in the Piceance Basin where we plan to drill approximately 700 wells over the next ten years, with first production expected in late 2007; and



•

in the Bakken Shale where we plan to drill approximately 300 locations over the next five years.

        We estimate that our 2007 production available for sale will average approximately 390 to 425 mboepd, excluding the impact of acquisitions and dispositions. With the developments we have under construction, we estimate our production available for sale will grow to 465 to 520 mboepd by 2010, excluding acquisitions and dispositions. Projected liquid hydrocarbon and natural gas production available for sale is based on a number of assumptions, including (among others) pricing, supply and demand for petroleum products, the amount of capital available for exploration and development, regulatory constraints, production decline rates of mature fields, timing of commencing production from new wells, drilling rig availability, inability or delay in obtaining necessary government and third-party approvals and permits, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the government or military response, and other geological, operating and economic considerations. These assumptions may prove to be inaccurate.

        In 2006, we issued a request for proposals to engage interested parties in a process that could lead to a Canadian oil sands venture. This process is intended to explore various commercial arrangements under which we would provide heavy Canadian oil sands crude oil processing capacity in exchange for an equity interest in a Canadian oil sands project through a joint venture, or other alternative business arrangements that potential partners may choose to propose.

        The above discussion includes forward-looking statements with respect to anticipated future exploratory and development drilling, the possibility of developing Blocks 31 and 32 offshore Angola, the timing of production from the Neptune development, the Piceance Basin, the combined Alvheim/Vilje development, the Volund field and the Corrib project. Some factors which could potentially affect these forward-looking statements include pricing, supply and demand for petroleum products, the amount of capital available for exploration and development, regulatory constraints, drilling rig availability, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other geological, operating and economic considerations. Except for the Alvheim/Vilje and Volund developments, the foregoing forward-looking statements may be further affected by the inability to or delay in obtaining necessary government and third-party approvals and permits. The possible developments in Blocks 31 and 32 could further be affected by presently known data concerning size and character of reservoirs, economic recoverability, future drilling success and production experience. The above discussion also contains forward-looking statements concerning a potential Canadian oil sands venture. Factors that could affect the formation of a Canadian oil sands venture include unforeseen difficulty in negotiation of definitive agreements, results of front-end engineering and design work, inability or delay in obtaining necessary government and third-party approvals, continued favorable investment climate, and other geological, operating and economic considerations. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Refining, Marketing and Transportation

        Throughout 2006, we remained focused on our strategy of leveraging refining and marketing investments in core markets, as well as expanding and enhancing our asset base while controlling costs. Our 2006 average daily crude oil throughput exceeded the record throughput achieved in 2005.

        In 2006, our Board of Directors approved a projected $3.2 billion expansion of our Garyville refinery by 180 mbpd to 425 mbpd, which will increase our total refining capacity to 1.154 mmbpd. We recently received air permit approval from the Louisiana Department of Environmental Quality for this project and construction is expected to begin in mid-2007, with startup planned for the fourth quarter of 2009. When completed, this expansion will enable the refinery to provide an additional 7.5 million gallons of clean transportation fuels to the market each day.

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        We have also commenced front-end engineering and design for a potential heavy oil upgrading project at our Detroit refinery which would allow us to process increased volumes of Canadian oil sand production and are undertaking a feasibility study for a similar upgrading project at our Catlettsburg refinery.

        In 2006, we signed a definitive agreement forming a joint venture that will construct and operate one or more ethanol production plants. Our partner in the joint venture will provide the day-to-day management of the plants, as well as grain procurement, and distillers dried grain marketing and ethanol management services. This venture will enable us to maintain the reliability of a portion of our future ethanol supplies. Together with our partner, we selected the venture's initial plan site, Greenville, Ohio, and construction has commenced on a 110 million gallon per year ethanol facility. The facility is expected to be operational as soon as the first quarter of 2008.

        The above discussion includes forward-looking statements concerning the planned expansion of the Garyville refinery, potential heavy oil refining upgrading projects and a joint venture that would construct and operate ethanol plants. Some factors that could affect the Garyville expansion project and the ethanol plant construction, management and development include necessary government and third party approvals, transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions and other risks customarily associated with construction projects. The Garyville project may be further affected by crude oil supply. These factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements. Factors that could affect the heavy oil refining upgrading projects include unforeseen difficulty in negotiation of definitive agreements, results of front-end engineering and design work, approval of our Board of Directors, inability or delay in obtaining necessary government and third-party approvals, continued favorable investment climate, and other geological, operating and economic considerations.

Integrated Gas

        Construction of the LNG production facility in Equatorial Guinea continues ahead of its original schedule with the first shipments of LNG projected for the second quarter of 2007. Construction is nearly complete and commissioning has commenced. We own a 60 percent interest in Equatorial Guinea LNG Holdings Limited. We are currently seeking additional natural gas supplies to allow full utilization of this LNG facility, which is designed to have a higher capacity and a longer life than the current contract to supply 3.4 million metric tons per year for 17 years.

        Once the Equatorial Guinea LNG production facility commences its principal operations and begins to generate revenue, we must assess whether or not EGHoldings continues to be a variable interest entity ("VIE"). We consolidate EGHoldings because it is a VIE and we are its primary beneficiary. Despite the fact that we hold majority ownership, we would not consolidate EGHoldings if it ceased to be a VIE because the minority shareholders have substantive participating rights. If EGHoldings ceased to be a VIE, we would account for our interest using the equity method of accounting.

        In 2006, with our project partners, we awarded a FEED contract for initial work related to a potential second LNG production facility on Bioko Island, Equatorial Guinea. The FEED work is expected to be completed during 2007. The scope of the FEED work for the potential 4.4 million metric tones per annum LNG facility includes feed gas metering, liquefaction, refrigeration, ethylene storage, boil off gas compression, product transfer to storage and LNG product metering. A final investment decision is expected in early 2008.

        Atlantic Methanol Production Company LLC underwent a scheduled maintenance shutdown in 2006, during which bottlenecks in several parts of the plant were also removed. Deliveries resumed in October 2006 and AMPCO expects to reach its full expansion capacity during 2007.

        The above discussion contains forward looking statements with respect to the timing and levels of production associated with the LNG production facility and the possible expansion thereof. Factors that could affect the LNG production facility include unforeseen problems arising from commissioning of the facilities, unforeseen hazards such as weather conditions and other operating considerations such as shipping the LNG. In addition to these factors, other factors that could potentially affect the possible expansion of the current LNG production facility and the development of additional LNG capacity through additional projects include partner approvals, access to sufficient natural gas volumes through exploration or commercial negotiations with other resource owners and access to sufficient regasification capacity. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

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Accounting Standards Not Yet Adopted

        In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities." This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. It requires that unrealized gains and losses on items for which the fair value option has been elected be recorded in net income. The statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. For us, SFAS No. 159 will be effective January 1, 2008, and retrospective application is not permitted. Should we elect to apply the fair value option to any eligible items that exist at January 1, 2008, the effect of the first remeasurement to fair value would be reported as a cumulative effect adjustment to the opening balance of retained earnings. We are currently evaluating the provisions of this statement.

        In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements." This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements but may require some entities to change their measurement practices. For us, SFAS No. 157 will be effective January 1, 2008, with early application permitted. We are currently evaluating the provisions of this statement.

        In September 2006, the FASB issued FASB Staff Position ("FSP") No. AUG AIR-1, "Accounting for Planned Major Maintenance Activities." This FSP prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods. We expense such costs in the same annual period as incurred; however, estimated annual major maintenance costs are recognized as expense throughout the year on a pro rata basis. As such, adoption of FSP No. AUG AIR-1 will have no impact on our annual consolidated financial statements. We are required to adopt the FSP effective January 1, 2007. We do not believe the provisions of FSP No. AUG AIR-1 will have a significant impact on our interim consolidated financial statements.

        In July 2006, the FASB issued FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109." FIN No. 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with SFAS No. 109, "Accounting for Income Taxes." FIN No. 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, transition and disclosure. For us, the provisions of FIN No. 48 are effective January 1, 2007. We do not believe adoption of this statement will have a significant effect on our consolidated results of operations, financial position or cash flows.

        In March 2006, the FASB issued SFAS No. 156, "Accounting for Servicing of Financial Assets – An Amendment of FASB Statement No. 140." This statement amends SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," with respect to the accounting for separately recognized servicing assets and servicing liabilities. We are required to adopt SFAS No. 156 effective January 1, 2007. We do not expect adoption of this statement to have a significant effect on our consolidated results of operations, financial position or cash flows.

        In February 2006, the FASB issued SFAS No. 155, "Accounting for Certain Hybrid Financial Instruments – An Amendment of FASB Statements No. 133 and 140." SFAS No. 155 simplifies the accounting for certain hybrid financial instruments, eliminates the interim FASB guidance which provides that beneficial interests in securitized financial assets are not subject to the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," and eliminates the restriction on the passive derivative instruments that a qualifying special-purpose entity may hold. For us, SFAS No. 155 is effective for all financial instruments acquired or issued on or after January 1, 2007. We do not expect adoption of this statement to have a significant effect on our consolidated results of operations, financial position or cash flows.

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QuickLinks

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Overview
2006 Operating Highlights
Critical Accounting Estimates
Management's Discussion and Analysis of Results of Operations
E&P Operating Statistics

RM&T Operating Statistics
Management's Discussion and Analysis of Financial Condition, Cash Flows and Liquidity

Summary of Contractual Cash Obligations
Summary of Contractual Cash Obligations Assumed by United States Steel

Management's Discussion and Analysis of Environmental Matters, Litigation and Contingencies
Outlook
Accounting Standards Not Yet Adopted