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:

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

w 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.

w 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.

w 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 forward-looking statements. For additional risk factors affecting our business, see Item 1A. Risk Factors in our 2008 Annual Report on Form 10-K.

Activities related to discontinued operations in Gabon and Ireland have been excluded from segment results and operating statistics.

Overview and Outlook

Exploration and Production ("E&P")

Production

Net liquid hydrocarbon and natural gas sales averaged 366 and 396 thousand barrels of oil equivalent per day ("mboepd") during the third quarter and first nine months of 2009 compared to 367 and 357 mboepd during the third quarter and first nine months of 2008. Sales increases in the first nine months of 2009 over the same period of 2008 primarily reflect the impact of liquid hydrocarbon production from the Alvheim/Vilje development offshore Norway which commenced production in mid-2008 and natural gas sales in Equatorial Guinea.

We continue to make progress on well completions at the Droshky development in the Gulf of Mexico on Green Canyon Block 244. Work is under way to tie back to the third-party operated Bullwinkle platform. First production is targeted for mid-2010. We hold a 100 percent operated working interest and an 81 percent net revenue interest in Droshky.

In September 2009, the Volund field offshore Norway produced first oil. This is the second major field tied to our Alvheim floating production, storage and offloading ("FPSO") vessel. While we expect our net share of the field's peak oil production to be 16,000 bpd, the timing of future production is subject to available processing capacity on the Alvheim FPSO. The first Volund well is functioning as a swing producer to the FPSO until there is some natural decline in the Alvheim field production. We hold a 65 percent operated interest in the Volund field.

Also offshore Norway, our partners announced the Marihone discovery, which is the first of five prospects near the Alvheim FPSO with tie back potential. The Marihone oil discovery is located in license PL340 about 12 miles south of the Volund and Alvheim fields. We hold a 65 percent operated working interest in Marihone.

We hold approximately 335,000 acres over the Bakken Shale play in North Dakota. We currently have three rigs running in our Bakken program and plan to add a fourth rig in the fourth quarter of 2009. Net production from Bakken in the third quarter of 2009 amounted to approximately 11 mboepd compared to 7 mboepd in the same quarter of 2008.

Index
Exploration

During the third quarter of 2009, we announced the Tebe discovery on Block 31 offshore Angola. We hold a 10 percent outside-operated interest in Block 31 and a 30 percent outside-operated interest in Block 32, pending the sale of two-thirds of our Block 32 interest as discussed below.

During the second quarter of 2009, we were awarded all 16 blocks bid in the Central Gulf of Mexico Lease Sale No. 208 conducted by the Minerals Management Service. Ten blocks are 100 percent Marathon, and the remaining six blocks were bid with partners, for a total of $62 million. We have acquired a total of 59 new leases from lease sales held 2007 through 2009.

In the second quarter of 2009, we were awarded a 49 percent interest and will serve as operator in the Kumawa Block offshore Indonesia, our third Indonesian offshore exploration block. The Kumawa Block encompasses 1.24 million acres.

The above discussions include forward-looking statements with respect to the timing and levels of future production and anticipated future drilling activity. Some factors that 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, timing of commencing production from new wells, 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. The foregoing forward-looking statements may be further affected by the inability to obtain or delay in obtaining necessary government and third-party approvals and permits. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Divestitures

During 2009, we have disposed of our exploration and production businesses in Ireland and certain producing assets in the Permian Basin of New Mexico and Texas. At September 30, 2009, agreements are pending to dispose of our exploration and production business in Gabon and certain assets under development in Angola. Our Irish and Gabonese exploration and production businesses have been reported as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for all periods presented. Assets and liabilities related to the Gabonese business are classified as held for sale in the consolidated balance sheet as of September 30, 2009.

In August 2009, we entered into an agreement to sell our operated fields offshore Gabon for $282 million, excluding any purchase price adjustments at closing, with an effective date of January 1, 2009. We expect to close the transaction by year-end 2009.

In July 2009, we entered into an agreement to sell an undivided 20 percent outside-operated interest in the Production Sharing Contract and Joint Operating Agreement in Block 32 offshore Angola for $1.3 billion, excluding any purchase price adjustments at closing, with an effective date of January 1, 2009. We will retain a 10 percent outside-operated interest in Block 32. We expect to close the transaction by year-end 2009, subject to government and regulatory approvals.

In June 2009, we closed the sales of a portion of our operated and all of our outside-operated Permian Basin producing assets in New Mexico and west Texas for net proceeds after closing adjustments of $293 million. A $196 million pretax gain on the sale was recorded. Net production from these operations averaged 8,150 barrels of oil equivalent per day ("boepd") in the first quarter of 2009. Our net proved reserves associated with these assets as of December 31, 2008, were 14 million barrels of oil equivalent ("mmboe").

In April 2009, we closed the sale of our operated properties in Ireland for net proceeds of $84 million, after adjusting for cash held by the sold subsidiary. A $158 million pretax gain on the sale was recorded. Net production from these operations averaged 5,000 boepd in the first quarter of 2009. Our net proved reserves associated with these assets as of December 31, 2008, were 6 million barrels of oil equivalent ("mmboe"). As a result of this sale, we terminated our pension plan in Ireland, incurring a charge of $18 million which reduced the gain on sale.

In June 2009 we entered into an agreement to sell the subsidiary holding our 19 percent outside-operated interest in the Corrib natural gas development offshore Ireland. Total proceeds will range between $235 million and $400 million, subject to the timing of first commercial gas at Corrib and closing adjustments. The fair value of the consideration for this asset was $311 million, which was less than its book value. A $154 million impairment of the held for sale asset was recognized in discontinued operations in the second quarter of 2009 (see Note 11 and Note 4). At closing on July 30, 2009, the initial $100 million payment plus closing adjustments was received. Additional proceeds of $135 million to $300 million will be received on the earlier of first commercial gas or December 31, 2012.

The above discussions include forward-looking statements with respect to pending divestitures. The divestitures could be adversely affected by customary closing conditions or affected by the inability to obtain or delay in obtaining necessary government and third-party approvals. The divestiture in Gabon could be further affected by consultation

with the Gabonese government. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Oil Sands Mining ("OSM")

Our bitumen production was 27 thousand barrels per day ("mbpd") in the third quarter and 26 mbpd in the first nine months of 2009.

The Athabasca Oil Sands Project ("AOSP") Phase 1 expansion is on track and anticipated to begin mining operations in the second half of 2010, and upgrader operations in late 2010 or early 2011.

In October, the Government of Canada and Government of Alberta jointly announced their intent to partially fund AOSP's Quest Carbon Capture and Storage ("Quest CCS") project. Under the terms of their letters of intent, the Government of Alberta would contribute 745 million Canadian dollars and the Government of Canada would provide 120 million Canadian dollars toward the project's development. A final investment decision on the Quest CCS project will be made at a later date, and is subject to regulatory approvals, stakeholder engagement, detailed engineering studies, as well as a final joint venture partner agreement. Marathon has a 20 percent interest in AOSP.

In the second quarter of 2009, the operator of AOSP offered three additional leases to the other joint venture partners for the Muskeg River Mine. Terms of the transaction were as agreed in the original 1999 AOSP Joint Venture Agreement. We elected to participate in these leases and our net proved reserves increased 168 million barrels.

The above discussion includes forward-looking statements with respect to the start of operations of the AOSP Phase 1 expansion. Factors that could affect the project are transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, delays in obtaining or conditions imposed by necessary government and third-party approvals and other risks customarily associated with construction projects. The foregoing forward-looking statements may be further affected by commissioning and start-up risks associated with proto-type equipment and new technology.

Refining, Marketing and Transportation ("RM&T")

Our total refinery throughputs were 4 percent higher in the third quarter of 2009 compared to the third quarter of 2008, but were relatively flat for the nine-month periods of the same years. Crude oil refined increased 7 percent in the third quarter of 2009. Lower throughputs in 2008 resulted primarily from weather-related events. Planned major maintenance activities were completed at our Canton, Ohio; Catlettsburg, Kentucky; Robinson, Illinois, and Garyville, Louisiana, refineries in the first nine months of 2009. In the first nine months of 2008, major maintenance activities occurred at our Detroit, Michigan; Garyville and Robinson refineries.

Ethanol volumes sold in blended gasoline increased to an average of 62 mbpd for the third quarter of 2009, an 8 percent increase over the same period of 2008. For the first nine months of 2009 we blended an average of 59 mbpd, or 15 percent more ethanol than in the same period of 2008. The future expansion or contraction of our ethanol blending program will be driven by the economics of ethanol supply and government regulations.

Third quarter 2009 Speedway SuperAmerica LLC ("SSA") same store gasoline sales volume increased 3 percent when compared to the third quarter of 2008, while same store merchandise sales increased by 12 percent for the same period.

As of October 31, 2009, the expansion of our Garyville, Louisiana refinery is approximately 98 percent complete with an on-schedule startup expected late in the fourth quarter 2009. This expansion will increase the Garyville refinery's crude oil refining capacity by 180,000 bpd, improving scale efficiencies and feedstock flexibility. We now forecast that the project will cost between $3.8 billion and $3.9 billion. In early January 2010, we plan to commence an extended turnaround at the existing base refinery in Garyville. The entire facility (base and expansion) is expected to reach full refining capacity by the second quarter of 2010.

Construction activities continue on the heavy oil upgrading and expansion project at our Detroit refinery with completion expected in the last half of 2012.

The above discussion includes forward-looking statements with respect to the Garyville and Detroit refinery expansion projects. Factors that could affect those projects include transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, delays in obtaining or conditions imposed by necessary government and third-party approvals, and other risks customarily associated with construction projects. These factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Integrated Gas ("IG")

Our share of LNG sales worldwide totaled 6,372 metric tonnes per day ("mtpd") for the third quarter of 2009 compared to 6,048 mtpd in the third quarter of 2008 and 6,583 mtpd in the first nine months of 2009 compared to 6,453

mtpd in the first nine months of 2008. These LNG sales volumes include both consolidated sales volumes and our share of the sales volumes of equity method investees. LNG sales from Alaska are conducted through a consolidated subsidiary. LNG and methanol sales from Equatorial Guinea are conducted through equity method investees.

We continue to invest in the development of new technologies to create value and supply new energy sources. In the first nine months of 2009, we recorded costs of approximately $45 million related to natural gas technology research, including our GTFTM technology. Similar spending in the same period of 2008 was $59 million.

Market Conditions


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 continue to be
volatile in 2009, with the following table listing benchmark crude oil and
natural gas price averages for the third quarter and first nine months of 2009
and 2008 to illustrate the volatility:

                                            Three Months Ended September 30,         Nine Months Ended September 30,
Benchmark                                       2009                  2008              2009                  2008
West Texas Intermediate ("WTI") crude
oil (Dollars per barrel)                   $         68.24         $    118.22     $         57.32         $    113.52
Brent crude oil (Dollars per barrel)       $         68.08         $    115.09     $         57.32         $    111.11
Henry Hub natural gas (Dollars per
mmbtu)(a)                                  $          3.39         $     10.25     $          3.93         $      9.74

(a) First-of-month price index per million British thermal units.

On average, crude oil prices in 2009 were lower than in 2008. Crude oil prices declined rapidly to lows around $40 per barrel in February 2009 from a high of over $140 per barrel in July 2008. By September 2009 prices had increased to near $70 per barrel.

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) typically sells at a discount to light sweet crude oil. Our international crude oil production is relatively sweet and is generally priced in relation to the Brent crude oil benchmark.

Natural gas prices on average were also lower in 2009 than in 2008. Our 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 price realizations may decrease.

Our worldwide E&P revenues during the third quarter and first nine months of 2009 were 47 and 46 percent lower than in the same periods of 2008, with the majority of the revenue decreases tied to these decreases in average commodity prices.

Oil Sands Mining

OSM segment revenues correlate with prevailing market prices for the various qualities of synthetic crude oil and vacuum gas oil we produce. Approximately two-thirds of our 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.

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 Alberta Energy Company ("AECO") natural gas sales index and crude prices respectively.

The table below shows benchmark prices that impacted both our revenues and variable costs for the third quarter and first nine months of 2009 and 2008:

                                            Three Months Ended September 30,         Nine Months Ended September 30,
Benchmark                                       2009                  2008              2009                  2008
WTI crude oil (Dollars per barrel)         $         68.24         $    118.22     $         57.32         $    113.52
Western Canadian Select (Dollars per
barrel)(a)                                 $         58.05         $    100.22     $         48.47         $     93.16
AECO natural gas sales index (Canadian
dollars per gigajoule)(b)                  $          2.78         $      7.45     $          3.59         $      8.19

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

(b) Monthly average of Alberta Energy Company day ahead index.

Excluding the impact of derivatives, our OSM segment revenues for the third quarter and first nine months of 2009 were lower than for the same periods of 2008, reflecting the impact of lower price realizations for synthetic crude oil and vacuum gas oil sales. Realizations were 45 percent lower in the third quarter and 51 percent lower for the first nine months of 2009, compared to the same periods of 2008.

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 spot market prices at major trading locations 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 refined into 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 for the Midwest and Gulf Coast markets and the sweet/sour differential for the third quarter and first nine months of 2009 and 2008:

                                            Three Months Ended September 30,          Nine Months Ended September 30,
(Dollars per barrel)                            2009                 2008              2009                    2008
Chicago LLS 6-3-2-1 crack spread           $         3.93         $      7.81     $         4.20         $           3.59
U.S. Gulf Coast LLS 6-3-2-1 crack spread   $         2.50         $      6.32     $         2.99         $           3.26
Sweet/Sour differential(a)                 $         5.64         $     11.38     $         5.62         $          12.64

(a) Calculated using the following mix of crude types: 15% Arab Light, 20% Kuwait, 10% Maya, 15% Western Canadian Select, 40% Mars.

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 manage price risk,

· the cost of products purchased for resale, and

· changes in manufacturing costs, which include depreciation.

Our refineries can process significant amounts of sour crude oil which may enhance our margin compared to what the change in the relevant crack spread indicators would suggest, as sour crude oil typically can be purchased at a discount to sweet crude oil. The amount of this discount can and does vary significantly and can therefore have a significant impact on our refining and wholesale marketing gross margin. Manufacturing costs are primarily driven by the cost of energy used by our refineries and the level of maintenance activities.

Our refining and wholesale marketing gross margin for the third quarter and first nine months of 2009 was 70 percent and 29 percent lower when compared to the same periods of 2008, consistent with changes in crack spreads, with the significantly reduced sweet/sour differential adding to the unfavorable impact.

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.

We own a 45 percent interest in a methanol plant located in Equatorial Guinea through our investment in Atlantic Methanol Production Company LLC ("AMPCO"). AMPCO's plant capacity is 1.1 million tones per annum, or 3 percent of 2008 world 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.

The impact of lower Henry Hub prices in the third quarter and first nine months of 2009 compared to the same periods of 2008 can be seen in decreased earnings from the LNG production facility although the production levels increased over the same periods. Our methanol realizations were also down during the third quarter, in line with global methanol prices.