We are a global integrated energy company with significant operations in the U.S., Canada, Africa and Europe. Our operations are organized into four reportable segments:

• Exploration and Production ("E&P") which explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis.

• Oil Sands Mining ("OSM") which mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and by-products.

• Refining, Marketing & Transportation ("RM&T") which refines, markets and transports crude oil and petroleum products, primarily in the Midwest, upper Great Plains, Gulf Coast and southeastern regions of the United States.

• Integrated Gas ("IG") which markets and transports products manufactured from natural gas, such as liquefied natural gas ("LNG") and methanol, on a worldwide basis, and is developing other projects to link stranded natural gas resources with key demand areas.

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.

We hold a 60 percent interest in Equatorial Guinea LNG Holdings Limited ("EGHoldings"). As discussed in Note 4 to the consolidated financial statements, effective May 1, 2007, we ceased consolidating EGHoldings. Our investment is accounted for using the equity method of accounting. Unless specifically noted, amounts presented for the Integrated Gas segment for periods prior to May 1, 2007, include amounts related to the minority interests.

Management's Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the information under Item 1. Business, Item 1A. Risk Factors, Item 6. Selected Financial Data and Item 8. Financial Statements and Supplementary Data.

Evaluation of Separation of Marathon's Businesses

On July 31, 2008, we announced that our board of directors would be evaluating the separation of Marathon into two independent, publicly-traded companies, each focused on its own set of business opportunities. On February 3, 2009, we further announced that our board concluded it is in the best interest of our shareholders to remain a fully integrated energy company.

Overview

Exploration and Production

Prevailing prices for the various qualities of crude oil and natural gas that we
produce significantly impact our revenues and cash flows. Prices were extremely
volatile in 2008 with the following table listing high and low spot prices
during the year for key benchmarks.



Benchmark                                        High              Date        Low          Date
WTI crude oil (Dollars per barrel)             $       145.29     July 3     $ 33.87     December 19
Brent crude oil (Dollars per barrel)           $       144.22     July 3     $ 33.66     December 24
Henry Hub natural gas (Dollars per mcf)(a)     $        13.11     July 1     $  6.47     November 1

(a) First-of-month price index.

On average, crude oil prices in 2008 were higher than in 2007. Crude oil prices climbed rapidly through the first half of 2008 based upon expected strong global demand, a declining dollar, ongoing concerns about supplies of

crude oil, and political unrest in the Middle East and elsewhere. Later in 2008, crude oil prices dropped more rapidly than they had climbed as the U.S. dollar rebounded and other countries entered recessions which decreased demand.

During 2008, the average spot price per barrel for WTI was $99.75, up from an average of $72.41 in 2007, but ended the year at $44.60. The average spot price per barrel for Brent was $97.26 in 2008, up from an average of $72.39 in 2007, but ended the year at $36.55. The differential between WTI and Brent average prices widened to $2.49 in 2008 from $0.02 in 2007. 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 oil benchmark.

Natural gas prices on average were higher in 2008 than in 2007. A significant portion of our U.S. lower 48 states 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 $2.18 per thousand cubic feet ("mcf") higher in 2008 than the 2007 average. Natural gas sales in Alaska are subject to term contracts. Our other major natural gas-producing regions are Europe and Equatorial Guinea, where large portions of our natural gas sales are subject to term contracts, making realized prices in these areas less volatile. As we sell larger quantities of natural gas from these regions, to the extent that these fixed prices are lower than prevailing prices, our reported average natural gas prices realizations may decrease.

E&P segment income during 2008 was up 57 percent from 2007, with revenue increases tied to these increases in average commodity prices accounting for almost half of the income improvement. Liquid hydrocarbon and natural gas sales volumes were also higher in 2008 than 2007.

Oil Sands Mining

Oil Sands Mining segment revenues correlate with prevailing market prices for the various qualities of synthetic crude oil and vacuum gas oil we produce. Roughly two-thirds of the normal output mix will track movements in WTI and one-third will track movements in the Canadian heavy sour crude oil marker, primarily Western Canadian Select. Output mix can be impacted by operational problems or planned unit outages at the mine or upgrader. During 2008, our average realized price for synthetic crude oil and vacuum gas oil was $91.90 per barrel, up from 2007, but ended the year at $24.97 per barrel impacted by a heavier yield in December and a seasonal decrease in the value of our heavy output.

The operating cost structure of the oil sands mining operations is predominantly fixed, and therefore many of the costs incurred in times of full operation continue during production downtime. Per unit costs are sensitive to production rates. Key variable costs are natural gas and diesel fuel, which track commodity markets such as the Canadian AECO natural gas sales index and crude prices respectively.

The table below shows benchmark prices that impact both our revenues and variable costs, listing high and low spot prices during the year.

Benchmark                                            High      Date      Low         Date
WTI crude oil (Dollars per barrel)                 $ 145.29   July 3   $ 33.87   December 19
Western Canadian Select (Dollars per barrel)(a)    $ 114.95    July    $ 23.18     December
AECO natural gas sales index (Canadian dollars
per gigajoule)(b)                                  $  11.34   July 1   $  5.42   September 19

(a) Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.

(b) Alberta Energy Company day ahead index.

Our OSM segment reported income of $258 million for 2008, reflecting synthetic crude oil and vacuum gas oil sales averaging 32 mboepd. Derivative instruments intended to hedge price risk on future sales have impacted revenues in the periods presented, with net gains of $48 million in 2008 and net losses of $53 million in 2007. In the first quarter of 2009, we entered into derivative instruments which effectively offset certain of our open derivative positions.

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.

Our 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, including the costs to transport these inputs to our refineries, the costs of purchased products and manufacturing expenses, including depreciation. The crack spread is a measure of the difference between market prices for refined products and crude oil, commonly used by the industry as an indicator of the impact of price on the refining margin. Crack spreads can fluctuate significantly, particularly when prices of refined products do not move in the same relationship as the cost of crude oil. As a performance benchmark and a comparison with other industry participants, we calculate Midwest (Chicago) and U.S. Gulf Coast crack spreads that we feel most closely track our operations and slate of products. Posted Light Louisiana Sweet ("LLS") prices and a 6-3-2-1 ratio of products (6 barrels of crude oil producing 3 barrels of gasoline, 2 barrels of distillate and 1 barrel of residual fuel) are used for the crack spread calculation. The following table lists calculated average crack spreads by quarter for the Midwest (Chicago) and Gulf Coast markets in 2008.

      Crack spreads

      (Dollars per barrel)         1st Qtr     2nd Qtr     3rd Qtr    4th Qtr       2008
      Chicago LLS 6-3-2-1         $    0.07   $    2.71   $    7.81   $   2.31     $ 3.27
      US Gulf Coast LLS 6-3-2-1   $    1.39   $    1.99   $    6.32   ($  0.01 )   $ 2.45

In addition to the market changes indicated by the crack spreads, our refining and wholesale marketing gross margin is impacted by factors such as the types of crude oil and other charge and blendstocks processed, the selling prices realized for refined products, the impact of commodity derivative instruments used to mitigate price risk and the cost of purchased products for resale. We process significant amounts of sour crude oil which can enhance our profitability compared to certain of our competitors, as sour crude oil typically can be purchased at a discount to sweet crude oil. Finally, our refining and wholesale marketing gross margin is impacted by changes in manufacturing costs, 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 2008 refining and wholesale marketing gross margin was the key driver of the 43 percent decrease in RM&T segment income when compared to 2007. Our average refining and wholesale marketing gross margin per gallon decreased 37 percent, to 11.66 cents in 2008 from 18.48 cents in 2007, primarily due to the significant and rapid increases in crude oil prices early in 2008 and lagging wholesale price realizations.

Our retail marketing gross margin for gasoline and distillates, which is the difference between the ultimate price paid by consumers and the cost of refined products, including secondary transportation and consumer excise taxes, also impacts RM&T segment profitability. While on average demand has been increasing for several years, there are numerous factors including local competition, seasonal demand fluctuations, the available wholesale supply, the level of economic activity in our marketing areas and weather conditions that impact gasoline and distillate demand throughout the year. In 2008, demand began to drop due to the combination of significant increases in retail petroleum prices and a broad slowdown in general activity. The gross margin on merchandise sold at retail outlets has historically been more constant.

The profitability of our pipeline transportation operations is primarily dependent on the volumes shipped through our crude oil and refined products 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 and declines during the fall and winter months, whereas distillate demand is more ratable throughout the year. As with crude oil, other transportation alternatives and system maintenance levels influence refined product movements.

Integrated Gas

Our 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. Our integrated gas operations include marketing and transportation of products manufactured from natural gas, such as LNG and methanol, primarily in the U.S., Europe and West Africa.

Our most significant LNG investment is our 60 percent ownership in a production facility in Equatorial Guinea, which sells LNG under a long-term contract at prices tied to Henry Hub natural gas prices. In 2008, its

first full year of operations, the plant sold 3.4 million metric tonnes. Our share of sales was 2.1 million tonnes. Industry estimates of 2008 LNG trade are approximately 175 million metric tonnes, which is about 25 percent of international natural gas trade. More LNG production facilities and tankers are being constructed. The recent worldwide economic downturn is expected to lower natural gas consumption in various countries; therefore, affecting near-term demand for LNG. Long-term LNG supply continues to be in demand as markets seek the benefits of clean burning natural gas. Market prices for LNG are not reported or posted. In general, LNG delivered to the U.S. is tied to Henry Hub prices and will track with changes in U.S. natural gas prices, while LNG sold in Europe and Asia is indexed to crude oil prices and will track the movement of those prices.

We own a 45 percent interest in a methanol plant located in Equatorial Guinea through our investment in AMPCO. Sales of methanol from the plant totaled 792,794 metric tonnes in 2008. Methanol demand has a direct impact on AMPCO's earnings. Because global demand for methanol is rather limited, changes in the supply-demand balance can have a significant impact on sales prices. The 2008 Chemical Markets Associates, Inc.'s World Methanol Analysis predicts demand for methanol in 2009 will be 43 million metric tonnes. Our plant capacity is 1.1 million, or 3 percent of total demand. Also included in the financial results of the Integrated Gas segment are costs associated with ongoing development of integrated gas projects, including natural gas technology research.

Integrated Gas segment income in 2008 was up 129 percent from 2007, primarily because the LNG production facility in Equatorial Guinea, which commenced operations in May 2007, operated for the full year.

2008 Operating Highlights

E&P

• We added net proved liquid hydrocarbon and natural gas reserves of 110 million barrels of oil equivalent ("boe"), excluding dispositions of 3 million boe, while producing 137 million boe during 2008. Over the past three years, we have added net proved reserves of 344 million boe, excluding dispositions of 48 million boe, while producing 396 million boe.

• We completed the operated Alvheim/Vilje development offshore Norway, with first production from Alvheim in June 2008 and from Vilje in July 2008.

• We completed the outside-operated Neptune development in deepwater Gulf of Mexico, which began producing in July 2008.

• We drilled a second appraisal well on the Droshky prospect in deepwater Gulf of Mexico and received Board approval to develop the prospect.

• We announced a successful discovery well on the Gunflint prospect in deepwater Gulf of Mexico.

• We were awarded 15 blocks at Outer Continental Shelf Lease Sale No. 206, and a second Indonesian offshore exploration block.

• We announced the Portia and Dione discoveries on deepwater Angola Block 31, bringing our total discoveries in Angola to 28.

• We received government approval to proceed with the first development project on Angola Block 31.

• The Volund development offshore Norway continues to progress on schedule toward first production in late 2009 and will be tied back to the Alvheim infrastructure.

RM&T

• We have completed approximately 75 percent of our Garyville, Louisiana, refinery expansion, which is scheduled to start-up in the fourth quarter of 2009.

• We commenced construction of the Detroit refinery heavy oil upgrading and expansion project, with start-up expected in mid-2012.

OSM

• Expansion 1 at the Athabasca Oil Sands Project ("AOSP") continues to proceed on schedule.

Divestitures

• We sold our 50-percent ownership in the Pilot Travel Centers LLC ("PTC") joint venture in a $700 million transaction.

• We sold our non-core outside-operated assets and associated undeveloped acreage in the Heimdal area offshore Norway for proceeds of $301 million.

• We reached an agreement to sell our producing assets in Ireland.

Consolidated Results of Operations: 2008 compared to 2007

Revenues are summarized in the following table.

 (In millions)                                                   2008         2007
 E&P                                                           $ 12,486     $  9,155
 OSM                                                              1,122          221
 RM&T                                                            64,481       56,075
 IG                                                                  93          218

 Segment revenues                                                78,182       65,669
 Elimination of intersegment revenues                            (1,207 )       (885 )
 Gain (loss) on U.K. gas contracts                                  218         (232 )

 Total revenues                                                $ 77,193     $ 64,552

 Items included in both revenue and costs and expenses:
 Consumer excise taxes on petroleum products and merchandise   $  5,065     $  5,163

E&P segment revenues increased $3,331 million in 2008 from 2007. Higher average liquid hydrocarbon and natural gas realizations account for over 70 percent of the revenue increase. Liquid hydrocarbon and natural gas sales volumes were also higher in 2008 than 2007. Sales volumes also benefited from a full year of natural gas sales to the Equatorial Guinea LNG production facility, which we co-own. Beginning mid-year, both the Alvheim/Vilje development offshore Norway and the Neptune development in the Gulf of Mexico contributed particularly to the liquid hydrocarbon sales increase. Because the majority of the natural gas sales increase was fixed-price sales to the LNG production facility in Equatorial Guinea, our average international natural gas realizations decreased. Our share of the income ultimately generated by the subsequent export of LNG produced by EGHoldings, as well as methanol produced by AMPCO is reflected in our Integrated Gas segment as discussed below.

Total International(b) 148 133

WORLDWIDE 211 197
Net Natural Gas Sales (Millions of cubic feet per day)(c)(d) United States 448 477 Europe 198 216 Africa 370 232

Total International 568 448

WORLDWIDE 1,016 925

Total Worldwide Sales (Thousands of barrels of oil equivalent per day) 381 351

Average Realizations(e)
Liquid Hydrocarbons (Dollars per barrel) United States $ 86.68 $ 60.15 Europe 90.60 70.31 Africa 90.29 66.09 Total International 90.40 67.15
WORLDWIDE $ 89.29 $ 64.86
Natural Gas (Dollars per thousand cubic feet) United States $ 7.01 $ 5.73 Europe 8.03 6.53 Africa 0.25 0.25 Total International 2.97 3.28
WORLDWIDE $ 4.75 $ 4.54

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

(b) Represents equity tanker lifting 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 net sales after royalties, except for Ireland where amounts are before royalties.

(d) Includes natural gas acquired for injection and subsequent resale of 32 mmcfd and 47 mmcfd in 2008 and 2007.

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

E&P segment revenues included derivative gains of $22 million in 2008 and losses of $15 million in 2007. Excluded from E&P segment revenues were gains of $218 million in 2008 and losses of $232 million in 2007 related to natural gas sales contracts in the United Kingdom that are accounted for as derivative instruments.

OSM segment revenues totaled $1,122 million in 2008 and $221 million in 2007, reflecting a full year of operations in 2008. Revenues were impacted by net gains in 2008 and net losses in 2007 on derivative instruments, which expire December 2009, that were held by Western at the acquisition date and intended to mitigate price risk related to future sales of synthetic crude oil. The 2008 net gain of $48 million included realized losses of $72 million and unrealized gains of $120 million, while less than $1 million of the $53 million net loss in 2007 was realized. Additionally, revenues were negatively impacted by reliability issues and the implementation of a revised tailings management plan that impacted ore grade. Sales of synthetic crude oil averaged 32 mbpd at an average realized price of $91.90 per barrel compared to a $71.07 average realized price for the period from the October 18, 2007, acquisition date through December of 2007.

RM&T segment revenues increased $8,406 million in 2008 from 2007. Higher refined product selling prices were realized in 2008, but lower sales volumes partially offset the price impact.

Income from equity method investments increased $220 million in 2008 from 2007. The Equatorial Guinea LNG production facility operated for the full year of 2008, accounting for most of the increased income, with 54 cargoes delivered in 2008 compared to 24 in 2007. In addition, there was an $81 million increase in PTC income due to higher retail margins. Offsetting these increases was the $40 million pretax impairment of our equity investment in two ethanol production facilities, losses generated by one of those facilities and lower income from AMPCO. AMPCO sales volumes and realized prices were lower in 2008 due to temporary reductions in available feedstock gas and plant reliability problems.

Net gain on disposal of assets increased $387 million as a result of the review of our portfolio of assets that commenced in 2008. We sold our outside-operated interests (24 percent of Heimdal field, 47 percent of Vale field and 20 percent of Skirne field) and associated undeveloped acreage in offshore Norway and our share of the PTC joint venture in 2008. Property sales in 2007, primarily related to sales of individual producing properties and retail outlets were not significant.

Cost of revenues increased $10,713 million in 2008 from 2007. The increases were primarily in the RM&T segment and resulted from increases in acquisition costs of crude oil. Acquisition costs for refinery charge and blendstocks and for purchased refined products also increased, but the impact of this increase was partially offset by the impact of lower refinery throughput.

Depreciation, depletion and amortization ("DD&A") increased $565 million in 2008 from 2007. The increase in 2008 primarily relates to new assets. Our oil sands assets operated for the full year of 2008 and two significant offshore developments, Alvheim/Vilje offshore Norway and Neptune in the Gulf of Mexico, began operating at mid-year.

Goodwill impairment expense of $1,412 million relates to our OSM reporting unit. During the fourth quarter of 2008, we tested our OSM reporting unit's goodwill for impairment and upon allocating fair value among the reporting unit's assets, there was no remaining implied fair value of goodwill as of December 31, 2008. See Note 16 to the consolidated financial statements for further information about the impairment.

Net interest and other financial income or costs reflected $50 million in costs for 2008 and $41 million of income for 2007, an unfavorable change of $91 million from 2007. Interest income decreased due to lower interest rates and . . .