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 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 436 and 415 thousand barrels of oil equivalent per day ("mboepd") during the second quarter and first six months of 2009 compared to 347 and 357 mboepd during the second quarter and first six months of 2008. These increases over the same periods of 2008 primarily reflect the impact of a full quarter of production from the Alvheim/Vilje development offshore Norway and the Neptune development in the Gulf of Mexico compared to partial quarters in 2008 when they commenced production. For the second quarter, worldwide natural gas sales are down 5 percent, primarily in the U.S. as a result of property sales, the timing of Alaska storage activities and natural decline in Gulf of Mexico, while natural gas sales in Equatorial Guinea have increased due to improved reliability at the LNG plant which purchase this natural gas.

We have drilled all four development wells on the Droshky discovery in the Gulf of Mexico on Green Canyon Block 244. Well completions are underway and the project is on track for our first production target of 2010.

Exploration

During the second quarter 2009, we announced the Oberon discovery on Block 31 offshore Angola. We also participated in 2 exploration wells in Block 31 and are in the process of drilling another exploration well. 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 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.

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.

Divestitures

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.

On June 24, 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. 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 fair value of the consideration for this asset was $311 million which was less than its book value. An impairment of $154 million was recognized in the second quarter of 2009 in discontinued operations. Additional gains or losses may be recognized until the final proceeds payment is received (see Note 10).

As a result of these dispositions, our Irish 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. The net loss on the sales reported in discontinued operations for 2009 was $14 million before income taxes.

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 $292 million. A $199 million pretax gain on the sale was recorded. Net production from these operations averaged 8,150 boepd in the first quarter of 2009. Our net proved reserves associated with these assets as of December 31, 2008, were 14 mmboe.

The above discussions include forward-looking statements with respect to the timing and levels of future production, anticipated future exploratory drilling activity and pending divestitures. 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 divestitures could also be adversely affected by customary closing conditions. 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 26 thousand barrels per day ("mbpd") in the second quarter and 25 mbpd in the first six months of 2009.

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. These additional reserve barrels will initially reduce our depreciation, depletion and amortization ("DD&A") rate per barrel by approximately 40 percent beginning in June 2009.

The Alberta government announced its decision to consider the proposed AOSP's Quest carbon capture and sequestration ("CCS") project, involving the Scotford upgrader, for possible government funding. The AOSP partners are currently working with the government on a letter of intent, after which a funding agreement will be negotiated. A final investment decision on the Quest project will be made at a later date, pending agreement on funding details with the Government of Alberta, regulatory approvals, stakeholder engagement, as well as final agreement of the joint venture partners.

The above discussion includes forward-looking statements with respect to future DD&A levels. The DD&A rate change is an estimate and actual future results may differ.

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

Our total refinery throughputs were 4 percent and 2 percent lower in the second quarter and first six months of 2009 than in the second quarter and first six months of 2008. Crude oil refined likewise decreased 6 percent and 3 percent in the same periods. The throughput declines in 2009 relate primarily to our level of planned maintenance activities. Planned major maintenance activities were completed at our Canton, Ohio; Catlettsburg, Kentucky; Robinson, Illinois, and Garyville, Louisiana, refineries in the first half of 2009. In the first and second quarters of 2008, major maintenance activities occurred at our Detroit, Michigan; Garyville and Robinson refineries.

Volumes under our ethanol blending program increased to 70 mbpd for the first six months of 2009, a 39 percent increase over the same period of 2008. For the second quarter of 2009 we blended an average of 73 mbpd, or 30 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.

Second quarter 2009 Speedway SuperAmerica LLC ("SSA") same store gasoline sales volume increased 3 percent when compared to the second quarter of 2008. This compares to an estimated demand decline of about 2 percent in our market area in the second quarter 2009, while same store merchandise sales increased by 14 percent for the same period.

As of July 31, 2009, the expansion of our Garyville, Louisiana refinery is 91 percent complete with an on-schedule startup expected in the fourth quarter 2009. We now forecast that the project will cost $3.7 billion, or approximately 10 percent more than our previously stated cost estimate. Delays in receipt of materials and fabricated equipment contributed to revisions in work execution plans, resulting in increased project costs. 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 6,611 metric tonnes per day ("mtpd") for the second quarter of 2009 compared to 6,402 mtpd in the second quarter of 2008 and 6,690 mtpd in the first six months of 2009 compared to 6,657 mtpd in the first six 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. The LNG production facility in Equatorial Guinea had operational availability of 99 percent in the second quarter of 2009.

We continue to invest in the development of new technologies to create value and supply new energy sources. In the second quarter and first six months of 2009, we recorded costs of approximately $18 and $36 million related to natural gas technology research, including our GTF™ technology. Similar spending in the same periods of 2008 was $22 million and $38 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 second quarter and first six months of 2009 and 2008 are listed below to illustrate the volatility:

                                                Three Months Ended June 30,           Six Months Ended June 30,
Benchmark                                        2009                2008              2009               2008
WTI crude oil (Dollars per barrel)           $      59.79       $       123.80     $      51.68       $      111.12
Brent crude oil (Dollars per barrel)         $      59.13       $       121.18     $      51.68       $      109.05
Henry Hub natural gas (Dollars per mcf)(a)   $       3.51       $        10.94     $       4.21       $        9.49

(a) First-of-month price index.

On average, crude oil prices in 2009 were lower than in 2008. Crude oil prices declined rapidly through February 2009 from a high of over $140 per barrel in July 2008. By June 2009 prices were approximately half of the previous year's maximum levels.

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 sold 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 prices realizations may decrease.

Our worldwide E&P revenues during the second quarter and first six months of 2009 were 41 and 45 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. Roughly 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 rate. 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 impacted both our revenues and variable costs for the second quarter and first six months of 2009 and 2008:

                                              Three Months Ended June 30,           Six Months Ended June 30,
Benchmark                                      2009                2008              2009               2008
WTI crude oil (Dollars per barrel)         $      59.79       $       123.80     $      51.68       $      111.12
Western Canadian Select (Dollars per
barrel)(a)                                 $      52.36       $       102.18     $      43.50       $       89.58
AECO natural gas sales index (Canadian
dollars per gigajoule)(b)                  $       3.28       $         9.67     $       4.00       $        8.56

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

(b) Alberta Energy Company day ahead index.

Excluding the impact of derivatives, our OSM segment revenues for the second quarter and first six 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 53 percent lower in the second quarter and 55 percent lower for the first six 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 second quarter and first six months of 2009 and 2008:

                                                Three Months Ended June 30,             Six Months Ended June 30,
(Dollars per barrel)                           2009                   2008              2009               2008
Chicago LLS 6-3-2-1 crack spread           $        5.73         $          2.71     $      4.34       $        1.42
U.S. Gulf Coast LLS 6-3-2-1 crack spread   $        3.59         $          1.99     $      3.25       $        1.70
Sweet/Sour differential(a)                 $        3.98         $         13.74     $      5.60       $       13.31

(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 second quarter and first six months of 2009 was higher when compared to the same periods of 2008, as anticipated based upon the improvement in crack spreads, but the significantly unfavorable sweet/sour differential offset most of the favorable crack spread 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. 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 Atlantic Methanol Production Company LLC ("AMPCO"). 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. AMPCO's plant capacity is 1.1 million tonnes, 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 second quarter and first six 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 second quarter. This was in line with methanol prices in the U.S. and European markets that averaged approximately $200 per metric tonne in the second quarter of 2009, down from approximately $485 per metric tonne in the same quarter of 2008.